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ICJ 8852 



Bureau of Mines Information Circular/1981 



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In Situ Mining Research 

Proceedings: Bureau of Mines 
Technology Transfer Seminar, 
Denver, Colo., August 5, 1981 



Compiled by Staff-Bureau of Mines 



UNITED STATES DEPARTMENT OF THE INTERIOR 



Information Circular 8852 



In Situ Mining Research 

Proceedings: Bureau of Mines 
Technology Transfer Seminar, 
Denver, Colo., August 5, 1981 



Compiled by Staff-Bureau of Mines 




UNITED STATES DEPARTMENT OF THE INTERIOR 
James G. Watt, Secretary 
BUREAU OF MINES 




/ N MS 




This publication has been cataloged as follows: 



Bureau of Mines Technology Transfer Seminars (1981 : Denver, 
Colo.) In situ mining research. 

(Bureau of Mines information circular ; 8852) 

Bibliography: p. 101-107. 

Supt. of Docs. no. : I 28.27:8852. 

1. In»situ processing (Mining)— Congresses. 2. Teaching— Con- 
gresses. I. Larson, William C. II. United States. Bureau of Mines. 
III. Title. IV. Series: Information circular (United States. Bureau of 
Mines) ; 8852. 



TN295.U4 [TN278.3] 622s [622'.7] 81-607050 AACR2 






PREFACE 

This Information Circular summarizes recent Bureau of Mines results cov- 
ering in situ mining research. The papers are only a sample of the Bureau's 
total effort to improve minerals productivity through its Resources Technology 
Program, but they represent the major research effort in the in situ mining 
area. Those desiring more information on the Bureau's Mineral Resources 
Technology Program in general, or information on specific research, should 
feel free to contact the Bureau of Mines, Division of Mineral Resources 
Technology, 2401 E Street, N. W. , Washington, D.C. 20241, or the appropriate 
author listed in the following proceedings. 



Ill 



CONTENTS 

Page 

Preface i 

Abstract 1 

Introduction, by Dennis V. D'Andrea 2 

In situ leach mining — current operations and production statistics, by 

William C. Larson 3 

Gold and silver leaching practices in the United States, by Peter G. 

Chamberlain and Michael G. Po jar 8 

Selection of lixiviants for in situ leach mining, by Daryl R. Tweeton 

and Kent A. Peterson. 17 

Advantages of using a chloride preflush before carbonate in situ leach 

mining , by Daryl R. Tweeton 25 

Restoring ground water quality following in situ leaching, by Daryl R. 

Tweeton 27 

Case history of a pilot-scale acidic uranium in situ leaching experi- 
ment, by Michael T. Nigbor, William H. Engelmann, and Daryl R. Tweeton 38 
Laboratory and field testing of drilling fluids to determine how they 

affect sandstone permeability, by Jon K. Ahlness, Donald I. Johnson, 

and Daryl R. Tweeton 46 

Applications of geophysical resistance measurements to in situ leaching, 

by Daryl R. Tweeton 54 

Cost and sensitivities model for in situ leach mining, by William C. 

Larson, George W. Toth, John R. Annett, and Orin M. Peterson 59 

Branched boreholes for in situ leach mining, by William C. Larson, 

Don W. Dareing, Ed T. Wood, and Don H. Davidson 71 

Geochemical kinetics model for in situ leach mining, by Robert D. 

Schmidt, Steven E. Follin, Kent A. Peterson, and Eric V. Level 86 

Appendix. — Bibliography of Bureau of Mines In Situ Mining Publications.. 101 



IN SITU MINING RESEARCH 

Proceedings: Bureau of Mines Technology Transfer Seminar, 
Denver, Colo., August 5, 1981 

Compiled by Staff— Bureau of Mines 



ABSTRACT 

These proceedings consist of an overview of the in situ mining research 
currently being carried out by the Bureau of Mines. The following papers 
emphasize two general aspects of the in situ mining method: the environment 
and productivity. Both areas are extremely important, particularly because in 
situ leach mining is a relatively new mining method from a commercial point of 
view. Topics covered include the restoration of ground water, the selection 
of lixiviants, in situ mining of commodities other than uranium, in situ min- 
ing costs, the application of resistance measurements to in situ mining, an 
acid leach mining case history, and the use of branched boreholes for in situ 
mining. A bibliography of Bureau of Mines publications on in situ mining is 
appended. 



INTRODUCTION 

by 

Dennis V. D' Andrea 1 



In situ leach mining is a relatively new method that has the potential 
of recovering a variety of mineral commodities such as copper, uranium, gold, 
silver, manganese, and nickel. This mining method can be applied to smaller 
or lower grade deposits that would otherwise not be mined, and also has major 
advantages when compared with conventional mining in the areas of health and 
safety and environment. Past experience has indicated that lower capital 
costs are required for in situ mining, and there is a quicker return on 
investment. 

Copper and uranium have been the two primary commodities extracted by 
in situ mining. In situ leaching of copper oxide deposits has been carried 
out at five locations in the Southwest. During 1980 there were 16 commercial- 
scale in situ uranium leaching operations at various stages of production and 
construction which accounted for about 10 percent of the domestic uranium 
production. Numerous companies have recently expressed interest in in situ 
mining other commodities such as manganese, gold, and silver, but there are 
presently no commercial operations. 

The Bureau of Mines began conducting research in 1971 to develop 
improved in situ leach mining techniques and to minimize environmental risks. 
The appendix lists publications that describe the in situ mining research that 
has been conducted or coordinated by the Bureau. Major research areas inves- 
tigated include well construction techniques, computer simulation, reducing 
environmental concerns, borehole mining, blasting to increase permeability, 
and economic analyses. The initial research was directed toward oxide copper 
deposits. In 1975 the emphasis shifted toward uranium in situ leaching min- 
ing, and current research is aimed at development of in situ raining methods 
for the recovery of a variety of mineral commodities. 

The goal of the Bureau's in situ leach mining investigations is to accel- 
erate the development and transfer to industry of improved techniques for in 
situ mining of marginal deposits, thus expanding the Nation's supply of criti- 
cal mineral commodities. 



Research supervisor, Blasting Technology and In Situ Mining, Twin Cities 
Research Center, Bureau of Mines, Minneapolis, Minn. 



IN SITU LEACH MINING- 
CURRENT OPERATIONS AND PRODUCTION STATISTICS 

by 

William C. Larson 1 



ABSTRACT 

Thus number of in situ leach operations has increased significantly 
since 1975. As of May 1980, there were 27 active projects, including 
18 commercial-scale operations (some of them under construction) and 9 pilot 
scale operations. 

The south Texas uranium district and Wyoming have been the most prominent 
areas in early field experiments as well as in commercial applications of this 
new recovery technique, and in situ leach tests are now being conducted in 
Colorado and New Mexico. The growing number of commercial-scale operations is 
evidence that in situ mining now offers a third option along with open pit and 
underground mining for winning uranium from sandstone host rocks. It is esti- 
mated that in 1979 about 9 percent of the Nation's total uranium production 
was from in situ mining. 

INTRODUCTION 

In situ leach mining should no longer be considered a "last resort" 
method for recovery of uranium in sandstone host rocks. More and more opera- 
tors are turning to this recovery technique as a viable alternative to conven- 
tional open pit or underground methods. By way of definition, in situ leach 
mining is that method where the ore mineral(s), in the original geologic set- 
ting, is preferentially leached from the host rock by the use of specific 
leach solutions and the mineral value(s) recovered. Briefly, in situ uranium 
mining consists of (1) injecting a suitable leach solution into the ore zone 
below the water table, (2) oxidizing, complexing, and mobilizing the uranium, 
and (3) recovering the pregnant solution through production wells for process- 
ing through an ion exchange system to recover the uranium. 

As is typical in the development of any new technology, there has been 
little public information available on in situ leach mining, particularly 
before 1977. In the past few years, however, in situ leach mining has evolved 
from totally experimental to commercial status. Thus, a number of papers have 
been published in the past 2 or 3 years on subjects related to in situ mining, 
such as design criteria, operating procedures, costs, environmental informa- 
tion, and general state-of-the-art information. 



Supervisory mining engineer, Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn. 



One aspect of in situ uranium leach mining that has not been discussed in 
the literature to any great extent is production data. This type of informa- 
tion is of great importance to the operators, to manufacturers associated with 
in situ leaching supplies, and to mineral forecasters, bankers, and individ- 
uals who make decisions regarding uranium exploration. The past 5 years have 
seen a significant growth in the in situ uranium mining industry, particularly 
in Texas and Wyoming, and many people may not be aware of the impact that in 
situ uranium mining has had on this country's uranium production, or of its 
potential for future production. The following discussion centers on two 
areas of in situ uranium mining: current operations and production statistics. 

CURRENT OPERATIONS 

Since the early 1960 's research and development efforts have yielded sig- 
nificant advances in in situ uranium mining technology. The first modern in 
situ uranium leach mine was operated by Utah Construction and Mining Co., now 
Utah International Inc. , at its Shirley Basin site in Wyoming. Utah Construc- 
tion used many of the same principles and techniques that are currently in use, 
such as continuous ion exchange systems, pattern drilling, and the use of 
leach solutions with an oxidizer. During 1961-63, the company experimented 
with many techniques, particularly with regard to well development procedures 
and leach solutions. By 1963, the company had experimented with and tried 
5 generations of well field designs and had drilled over 100 well field pat- 
terns in an attempt to optimize recoveries. From 1963 to 1969 in situ mining 
was the only method used by this company for uranium production. After 1969 
the in situ leach operation was replaced by open pit mining. 

Between 1969 and the early 1970' s numerous research and development 
activities were taking place in the industry, and pilot tests expanded from 
the laboratory into the field. In the mid-1970 's small-scale pilot tests 
were being conducted in Wyoming, New Mexico, and Texas. 

Following successful field testing at the Clay West site, the Atlantic 
Richfield Co. initiated the first commercial-scale in situ uranium mining 
operation in Texas in 1975. The Clay West mine, operated by U.S. Steel Corp., 
is located in Live Oak County northwest of Corpus Christi. Twelve additional 
commercial-size operations in Texas have been in various stages of production 
since the startup of the Clay West site. Table 1 summarizes the status of in 
situ uranium leach mining operations in Texas. 



TABLE 1 . - Status of uranium in situ leach mining operations In May 1980 



Firm 



Operation 



Commercial scale 



Pilot scale 1 



TEXAS 



Caithness , 

Conoco < 

Everest Minerals Corp , 

Intercontinental Energy Corp. 
Mobil Oil Co , 



Texaco , Inc < 

Union Carbide Corp...., 
Uranium Resources Inc., 
U.S. Steel , 

U.S. Steel— N.M.U. Inc. 
Wyoming Mineral Corp.., 



Hobson 

Zamzow, Pawnee 2 
Holiday-El Mesquite, 
Nell, O'Hern. 

Palangana 

Benavides, Longoria 

Burns 

Boots, Clay West, Moser 

Bruni, Sulfur Creek 



McBryde. 
Trevino. 



Hobson. 



WYOMING 



Cleveland Cliffs joint venture 

Exxon Minerals U.S. A 

Ker r-McGee 

Nubeth joint venture 

Ogle Petroleum 

Rocky Mountain Energy 

Rocky Mountain Energy joint venture.... 

Teton Exploration 

Wyoming Mineral Corp 



Highland 3 

Bison Basin 3 
Nine Mile Lake 1 * 
Irigaray 



Collins Draw. 

Bill Smith. 
Sundance. 

Reno Ranch. 

Luemberger. 



NEW MEXICO 



Mobil Oil Co, 



Crown Point 



COLORADO 



Union Oil-Power Resources joint venture Keota 5 



1 Pilot-scale operations other than those listed are known to exist in Texas, 

Wyoming, and New Mexico. 
Restoration stage. 
3 Commercial scale planned 1980. 
^Commercial scale planned 1983. 
Commercial scale planned 1981. 

Encouraged by the apparent success of in situ uranium leach mining, 
companies have pilot tests in operation or under construction in other major 
uranium-producing States, such as Wyoming, New Mexico, and Colorado. As of 
May 1980, there were eight operators in Wyoming in some stage of in situ 
leaching development, covering nine projects. Several operators have com- 
pleted research and development tests at more than one site. Table 1 shows 
the status of in situ uranium leaching mining operations in Wyoming as of May 
1980. Finally, Colorado and New Mexico each had at least one active pilot- 
scale operation as of May 1980, as shown in table 1. These figures bring the 
total number of projects in all states to 27, including pilot or commercial 
scale. 



Several other States have received increased interest in in situ uranium 
leaching, including Montana, Arizona, South Dakota, and California, although 
as yet no pilot-scale studies have been initiated in these States. The above 
examples were obtained from a variety of public sources of information, and 
undoubtedly other in situ uranium mining projects are in various stages of 
planning. 

PRODUCTION STATISTICS 

The previous section discussed the growth of in situ uranium mining oper- 
ations through 1980. This section discusses the in situ uranium mining pro- 
duction capabilities and estimated production from 1975 through 1982. There 
are two reasons for presenting the following material. First, very little 
information has been published in the literature, and therefore a void exists 
in this area. Second, uranium production from in situ mining is a new tech- 
nology, and many people may have underestimated its growth during the past 
5 years. For example, table 2 shows the published figures on rated capacities 
of the commercial-scale in situ mining operations. Companies often publish, 
in a variety of sources, a figure that represents the rated annual capacity 
of an operation, given suitable head grades to the processing plant as well 
as anticipated flow rates. Such production figures are realistic based on 
the information available at the time the plant was built. They are not 
actual uranium in situ mining production figures, but they do give a base or 
frame of reference from which to estimate actual production. 

TABLE 2. - Rated capacities of commercial-scale uranium in situ leach 
mining operations — current and near-term projects 



Operation 



Rated capacity 



Lb/yr 



Kg/yr 



Everest Minerals Corp. (Hobson) 

Exxon Minerals — U.S.A. (Highland) 

Intercontinental Energy Corp. (Zamzow) 

Mobil Oil Co. (Holiday-El Mesquite) 

Mobil Oil Co. (Nell) 

Mobil Oil Co. (O'Hern) 

Ogle Petroleum (Bison Basin) 

Rocky Mountain Energy joint venture (Nine Mile Lake) 

Union Carbide Corp. (Palangana) 

Union Oil — Power Resources joint venture (Keota).... 

Uranium Resources Inc. (Benavides) 

Uranium Resources Inc. (Longoria) 

U.S. Steel (Burns) 

U.S. Steel — N.M.U. (Boots, Clay West, Moser) 

Wyoming Mineral Corp. (Bruni) 

Wyoming Mineral Corp. (Irigaray) 

Wyoming Mineral Corp. (Sulfur Creek) 



150,000 
750,000 
250,000 
650,000 
100,000 
175,000 
400,000 
500,000 
300,000 
500,000 
300,000 
100,000 
1,000,000 
1,000,000 
250,000 
500,000 
500,000 



68,000 
340,200 
113,400 
294,800 

45,300 

79,400 
181,400 
226,800 
136,000 
226,800 
136,000 

45,300 
453,600 
453,600 
113,400 
226,800 
226,800 



In the last 5 years, production from in situ mining has increased con- 
siderably. Table 3 shows an historical comparison between the growth rates 
(rated capacities) of the industry and the estimated uranium production. If 
this trend continues, in situ uranium mining will be a logical third alter- 
native for the extraction of uranium from sandstone host rocks. Table 4 shows 
the percentage of uranium produced by in situ mining compared with the annual 
production of uranium by all methods. As can be seen from this figure, ura- 
nium production by in situ mining, particularly since 1976, has been 
significant. 

TABLE 3. - Estimated production versus rated capacities of uranium 
in situ leach mining operations, 1975-82 



Year 



Rated capacity 



Lb/yr 



Kg/yr 



Estimated production 



Lb/yr 



Kg/yr 



1975 

1976 

1977 

1978 

1979 

1980 e 

1981 e 

1982 e 

e Estimated. 



500 
1,000 
2,700 
2,975 
3,700 
5,700 
6,500 
7,650 



,000 
,000 
,000 
,000 
,000 
,000 
,000 
,000 



226,800 
453,600 
1,224,700 
1,349,400 
1,678,000 
2,585,500 
3,084,400 
3,583,400 



150,000 
500,000 
1,300,000 
2,200,000 
3,000,000 
4,000,000 
4,300,000 
5,600,000 



68,000 

226,800 

589,600 

997,900 

1,587,600 

1,814,300 

2,086,500 

2,540,000 



TABLE 4. - Percentage of uranium produced by in situ mining 
compared with production by other methods 



Year 


Total concentrate 
production, 1 lb 


In situ mining 
productivity,® lb 


Percent of 
total 


1975 


23,200,000 
25,494,000 
29,880,000 
36,980,000 
37,460,000 
40,000,000 


150,000 
500,000 
1,300,000 
2,200,000 
3,000,000 
4,000,000 


0.6 


1976 


2 


1977 


4 


1978 


6 


1979 


8 




10 



e Estimated. 

^•Statistical Data of the Uranium Industry. Dept. of Energy, 650- 
100(80), Grand Junction, Colo., 1980. 



SUMMARY 



In summary, several observations can be made regarding uranium in situ 
mining in the United States. First, the number of in situ mining operations 
in the United States is expanding at an impressive rate. Second, the esti- 
mated production figures show that uranium produced by in situ mining is a 
significant percentage of the Nation's uranium output. Third, in the opinion 
of many, this mining method is a viable alternative for the recovery of ura- 
nium from sandstone host rocks. 



GOLD AND SILVER LEACHING PRACTICES IN THE UNITED STATES 

by 
Peter G. Chamberlain 1 and Michael G. Pojar 2 



ABSTRACT 

Many new gold and silver mining operations have been established as a 
result of higher gold and silver prices. Leaching processes capable of 
extracting gold and/or silver from small deposits and/or lower grade ores 
have become attractive to many precious metal mine operators. This paper 
discusses operating principles associated with gold and silver leach mining. 
Problems confronting potential leaching operations are also discussed along 
with research projects in progress to resolve these problems. 

INTRODUCTION 

Treatment methods applicable to comparatively high-grade gold and silver 
ores include gravity concentration, amalgamation, flotation, cyanidation, or 
direct smelting. Such processes involve high capital investments as well as 
high operating costs. A conventional cyanidation plant used in processing 
gold and silver ores usually includes crushing, fine grinding, and agitation 
leaching in cyanide solutions, countercurrent decantation in thickeners for 
separating the pregnant solution, clarification of this solution by filtering, 
deaeration by vacuuming, and precipitation of the precious metals by zinc pow- 
der. It is obvious that such a processing scheme is costly from the viewpoint 
of capital investment and operating cost. For this reason, such processes are 
not economically justified for lower grade ores. 

Many of the known and newly discovered gold and silver deposits are low 
in gold and/or silver content, have limited reserves, or contain other min- 
erals that make processing by conventional gravity and cyanidation methods 
impractical. Such lower grade and refractory deposits pose a big challenge to 
modern extraction technology. 

The gold and/or silver in small and low-grade deposits for which conven- 
tional mining and milling are too costly might be economically recoverable by 
leaching or solution mining methods. Solution mining is the extraction of 
metals by leaching from ores located within the confines of a mine, or in 
dumps, ore heaps, slag piles, and tailing ponds. 

If the ore is mined or gathered from old mine waste rock piles and hauled 
to specifically prepared pads for leaching, the method is termed "heap" leach- 
ing (fig. 1). The rock is frequently, but not always, crushed before being 

^Group supervisor, Mine Drainage, Leaching Processes and Water Pollution, 
fining engineer, Blasting Technology and In Situ Mining. 
Both authors are with the Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn. 



Influent leaching solution 



Solution makeup 
tank 



inq pad 




Solu 
sprays 



\ Barren solution 
~l from processing 
plant 



i. To processing 
plant 



Pump 



FIGURE 1. - Schematic of a heap leaching operation. 



^1 




Barren solution 
from processing V 
plant ' 



Solution makeup 
tank 



Influent solution sprays 

JJi it. it V 4 



■Waste rock 
dump 




Pregnant solution 
drainage 



To processing ( ♦- 
plant 




Pump 



FIGURE 2. - Schematic of a dump leaching operation. 



10 



Exposed Ore Body 



Processing 
plant 



r~ wm^ 




Barren solution 
makeup tank 




; L, — Perforated 
?rC casing 

Recovery 
well 



Pump 



Buried Ore Body 



placed on the pad. If old 
mine waste rock piles or 
dumps are judged to contain 
sufficient mineral value to 
justify leaching and the 
solutions can be controlled 
without appreciable losses, 
the pile is "dump" leached 
(fig. 2). Finally, if the 
ore is broken and left in 
place or if it will allow 
proper fluid flow without 
blasting, it can be leached 
"in situ," or in place 
(fig. 3). An exposed ore 
body can be leached in situ 
by spraying solution on the 
surface and collecting it 
in recovery wells after it 
has percolated down through 
the ore. For buried ore 
bodies, the solution must 
be forced into the forma- 
tion via injection wells 
and recovered from adjacent 
recovery wells. 

Basically leaching 
involves spraying a cyanide 
solution onto the ore, or 
the injection of a cyanide 
solution into an ore body to 
dissolve the gold or silver, 
collecting the solution con- 
taining the dissolved metals 
and recovering the metal 
from the leaching solution. 
By eliminating milling, 
leaching reduces capital 
cost and startup time for new operations. Operating costs are likewise sig- 
nificantly lower. 




Ore 
body 



Pump 



FIGURE 3. - Schematic of an in situ leaching operation. 



LEACHING OPERATIONS 



Gold and silver leaching operations are concentrated predominantly in the 
Western United States, along a broad belt coinciding with the mountain ranges 
that have historically hosted the bulk of our Nation's precious metal mining 
activity. Approximately 84 operations have been or are known to be actively 
using leaching techniques (either heap or dump) to extract gold and silver 
minerals on either a test or a commercial scale (table 1). The majority of 
these operations are located in Nevada and Arizona. The principal ones are 
shown on figure 4. 



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14 




FIGURE 4. - Gold and silver leaching operation location. 



15 



The extractable gold is generally deposited as native or free gold, often 
associated with pyrite. Silver is generally deposited in compound form. The 
easiest ores to leach are those that have been weathered or oxidized. The 
average or typical ore grades that can be successfully leached economically 
include gold ores ranging from 0.01 to 0.03 oz Au/ton, and silver ores ranging 
from 1.0 to 4.0 oz Ag/ton. 

Ores that are treated by heap leaching are — 

1. Mined or gathered together from lean ore or waste dumps. 

2. Crushed (optional). 

3. Placed on specially prepared, lined leach pads using scrapers, 
trucks, or bulldozers. 

4. Leached with sodium cyanide solution. 

Ores that are treated by dump leaching are leached with a sodium cyanide 
solution. 

Ores that are treated in situ are — 

1. Rubblized in-place. 

2. Leached with a sodium cyanide solution. 

Although it is possible to leach gold and silver with several solutions, 
all current operations use weak cyanide solution. Leach solutions are applied 
generally with sprays of either the oscillating or the fixed variety. After 
percolating down through the ore, the solution drains off and is collected in 
a holding pond. The gold and silver are then recovered from the pregnant 
leach solutions by precipitation with zinc dust or by adsorption onto acti- 
vated carbon. Each method of metal recovery has its various advantages and 
disadvantages. Selection of one system over the other will depend on the 
specific conditions present at the leach operation. 

LEACHING PROBLEM AND RESEARCH 

Several problems hamper the broader application of leaching methods for 
recovering gold and silver. These problems are listed below: 

1. Presence of clay or clay-sized particles, which retards leach solu- 
tion percolation. 

2. "Tight" or impermeable matrix, which reduces leach solution contact 
with the metal value in the matrix. 

3. Inclement weather conditions that prohibit extended leaching 
activities. 



16 



4. Leach solution loss through evaporation. 

5. Presence of refractory-type ores that inhibit cyanide leaching. 

The Bureau of Mines has been active for many years in the development of 
new techniques for recovering and processing gold and silver ores. A major 
aim or effort has been to develop applied technology to help increase the 
domestic production of the vital minerals such as precious metals. Two cur- 
rent studies are — 

1. Particle agglomeration techniques to improve percolation and recovery 
rates during heap leaching. 

2. Feasibility study to evaluate in situ leach mining of gold and silver 
ores. 

CONCLUSION 

Gold and silver solution mining (leaching) operations have sprung up in 
many mining districts of the Western United States. Over 80 operations have 
been identified that have conducted tests or established commercial operations. 
The geology favoring leachable deposits seems to be in regions that have been 
subjected to folding, faulting, and volcanic activity. Leaching practices are 
offshoots from 70 or 80 years of conventional milling operations wherein gold 
and silver have been dissolved with cyanide. Instead of processing the ore 
through a complex mill circuit, leaching operators dissolve the metal directly 
from run-of-mine or crushed rock. Gold and silver are then recovered from the 
pregnant liquors using the traditional zinc precipitation process or by the 
relatively new charcoal adsorption process. Although gold and silver can be 
leached in situ or from waste rock dumps, heap leaching on specially prepared 
pads is the predominant method. 

The main problems encountered in heap leaching operations are poor solu- 
tion percolation due to high clay content in the ore and mineralogy that is 
detrimental to leaching reactions. Cold temperatures and lime buildup in the 
solution distribution system also can severely affect the economics of an 
operation. Bureau research on particle agglomeration offers intriguing pos- 
sibilities for reducing poor percolation rates due to clay. The problems of 
possible refractory ores must be worked out in the laboratory in advance of 
the decision to leach and are not discussed herein. At least one company has 
experimented with submersible kerosene heaters for warming leaching solutions, 
and results to date have been promising. Conversion from lime to NaOH reduces 
lime buildup in distribution lines; several operators have experimented with 
Bagdad wigglers in additional attempts to minimize maintenance costs associ- 
ated with lime buildup. These wigglers, named for their original use at the 
Bagdad copper mine, are easily constructed from 9-inch segments of thick- 
walled gum rubber tubing. 



17 



SELECTION OF LIXIVIANTS FOR IN SITU LEACH MINING 

by 
Daryl R. Tweeton 1 and Kent A. Peterson 2 



ABSTRACT 

This paper provides information to assist in selecting a lixiviant (leach 
solution) for in situ uranium leaching. The cost, advantages, and disadvan- 
tages of lixiviants currently used and proposed are presented. Laboratory 
and field tests are described, and applications of geochemical models are 
discussed. 

INTRODUCTION 

Selection of the lixiviant is of critical importance to the success of 
an in situ leaching operation. The lixiviant affects not only the recovery 
of uranium and the cost of chemicals, but also the difficulty of meeting envi- 
ronmental regulations concerning restroation of ground water quality after 
leaching. 

No data specifically on lixiviant selection have previously been made 
available to the public. Much research has been done by companies, but the 
results have usually been considered proprietary. However, useful literature 
is available on topics that are important parts of the lixiviant selection 
process. The chemistry of conventional milling is thoroughly discussed by 
Merritt. 3 The similarities in chemistry between milling and in situ leaching 
make this a very useful reference. Extensive column leaching studies were 
performed by Westinghouse Electric Corp. for the Bureau of Mines Salt Lake 
City Research Center. ^ The influence of various lixiviants on the difficulty 
of restoring the ground water quality after leaching is an important factor 
and is discussed in several publications. 5 

Research physicist, Twin Cities Research Center, Bureau of Mines, Minneapolis, 

Minn. 
^Geologist, Twin Cities Research Center, Bureau of Mines, Minneapolis, Minn. 
3 Merrit, R. C. The Extractive Metallurgy of Uranium. Colorado School of 

Mines Research Institute, Golden, Colo., 1971, 576 pp. 
'♦Grant, D. C. In Situ Leaching Studies of Uranium Ores — Phase IV. BuMines 

Open File Rept. 52-79, 1978, 497 pp.; available from National Technical 

Information Service, Springfield, Va. , PB 296 336/AS. 
Jasper, D. R. , H. W. Martin, L. D. Munsey, R. B. Bhappu, and C. K. Chase. 

Environmental Assessment of In Situ Mining. BuMines Open File Rept. 101-80, 

1979, 292 pp.; available from National Technical Information Service, 

Springfield, Va., PB 81-106783. 
Thompson, W. E., W. V. Swarzenski, D. L. Warner, G. E. Rouse, 0. F. Carring- 

ton, and R. Z. Pyrih. Groundwater Elements of In Situ Leach Mining of 

Uranium. Prepared for U.S. Nuclear Regulatory Commission, August 1978, 

173 pp.; available from National Technical Information Service, Springfield, 

Va., NUREG/CR-0311. 



18 



Because of the importance of the subject to in situ uranium leaching, and 
because of the lack of previously published information, the Bureau of Mines has 
prepared Information Circular 8851 on this topic, which will be published later this 
year. This paper summarizes that Information Circular. 



Lixiviants that 
of ammonium carbonate 
sulfuric acid. Potas 
been considered too e 
leaching carbonaceous 
contain an anion that 
state. The cation do 
important because of 
restoration. 



AVAILABLE LIXIVIANTS 

have been used for in situ uranium leaching include solutions 
-bicarbonate, sodium carbonate-bicarbonate, carbon dioxide, and 
sium carbonate-bicarbonate is technically attractive but has 
xpensive. Hydrochloric and nitric acids have been proposed for 
ore. The carbonate-bicarbonate and sulfuric acid lixiviants 
will form a soluble complex with uranium in its +6 charge 
es not directly affect the solubility of the uranium but is 
its effect on permeability, cost, and ground water quality 



An oxidizer is required to convert unoxidized uranium from its insoluble +4 
charge state to its soluble +6 charge state. Oxidizers that have been used include 
oxygen, hydrogen peroxide, and sodium chlorate. 



The costs, not including delivery, of chemicals used for making lixiviants are 
listed in table 1 in the units in which the market prices are commonly expressed and 
in dollars per kilogram. Costs were obtained from discussions with suppliers and 
leaching companies and from published prices in late 1980. 6 These units are not the 
most useful for comparing costs because they do not directly compare the cost of pro- 
viding the significant component. For example, 1 kg of potassium carbonate provides 
less carbonate than 1 kg of ammonium carbonate. 

TABLE 1 . - Costs of chemicals used for making lixiviants 



Chemical 



Form 



Cost, 100-pct basis 



Per ton 



Per kg 



CO 2 

NH 3 

NaOH 

Na 2 C0 3 

NaHC0 3 

NaHC0 3 »Na 2 C0 3 »2H 2 
KOH 



K 2 C0 3 . 
KHC0 3 . 
H 2 S0 4 . 
HN0 3 .. 
HC1... 
2 .... 



H 2 2 ... 
NaC10 3 . 



Compressed and cooled liquefied gas 1 

Ammonia fertilizer 

Caustic soda, liquid, 50 pet at $250/ton. 

Soda ash. 

Flakes or powder 

Sodium sesquicarbonate granules. 

Caustic potash, liquid, 45 pet KOH at 

$11/100 lb. 
Liquid, 47 pet K 2 C0 3 at $11,75/100 lb.... 

Granulated, technical-grade 

Liquid, concentrated, virgin 

Liquid, 58.5 to 68 pet HN0 3 

Liquid, 37 pet HC1 at $70/ton 

Liquid, at $0.40 to $0.60/100 cu ft of 2 

gas at 1 atm and 25° C (1 lb = 12.08 cu 

ft). 

Liquid, 50 pet H 2 2 at $0.29/lb 

Powder or flakes 



$60- $200 
200 
500 

90 
240 

96 
490 

500 
280 
80 
120 
190 
2 97 
3 145 

1,160 
400 



$0.07-$0.22 
.22 
.55 
.10 
.26 
.11 
.54 

.55 
.31 
.09 
.13 
.21 
2 .11 
3 .16 

1.28 
.44 



^Depending on annual use. 

2 Texas. 

^Wyoming. 



See text. 



6 Chemical Marketing Reporter. Sept. 22, 1980, 43 pp. 



19 



To facilitate comparing the costs, tables 2, 3, and 4 present the cost 
per kilogram-mole and per pound-mole of alkaline lixiviants, acid lixiviants, 
and oxidizers, respectively. Table 2 lists the costs of bicarbonate and car- 
bonate lixiviants separately to permit calculating the cost of a lixiviant 
containing any proportion of the two. These lixiviant costs were calculated 
using the costs of chemicals in table 1, so changes in those chemical prices 
will cause proportionate changes in the corresponding lixiviant costs. The 
cost of $80 per ton of carbon dioxide used in formulating table 2 is typical, 
but it can vary a great deal. 

TABLE 2 . -Summary of alkaline lixiviant costs, advantages, and disadvantages 



Lixiviant 



Cost 



Per 
kg-mole 



Per 
lb-mole 



Ppm U 3 8 
paying 1 for 
3 g/1 anion 



Advantages and 
disadvantages 



Ammonium lixiviants: 

NH 4 HC0 3 

(NH^COa 

Sodium lixiviants: 
From soda ash: 

NaHC0 3 

Na 2 C0 3 

From caustic soda: 

NaHC0 3 

Na 2 C0 3 

From sodium 
sesquicarbonate : 

NaHC0 3 

Na 2 C0 3 

Potassium lixiviants: 
From caustic potash: 

KHC0 3 

K 2 C0 3 

From granules: KHC0 3 
From 47-pct K 2 C0 3 
solution: 
K 2 C0 3 

C0 2 



$7.63 
11.38 



7.19 
10.52 

25.93 
47.98 



8.67 
17.60 



33.56 
63.26 
30.90 



76.18 
2 3.88 



$3.46 
5.16 



3.27 
4.77 

11.76 
21.76 



3.93 
7.98 



15.22 
28.69 
14.00 



34.55 



1.76 



5.7 
8.6 



5.4 
8.0 



19 
36 



6.5 
13 



25 
48 
23 



58 



2 3 



2.9 



^suming $66/kg for U 3 08 and neglecting recycling. 
2 Assuming $80/ton. 
3 For 3 g/1 HC0 3 . 



Little effect on per- 
meability. Difficult 
to meet restoration 
requirements. 



Relatively easy to meet 
restoration require- 
ments. Can reduce 
permeability. 



Little effect on 
permeability, should 
be relatively easy to 
meet restoration 
requirements. Expen- 
sive unless preceded 
by chloride preflush. 

Cheap, little effect 
on permeability, easy 
to meet restoration 
requirements. Not 
effective in all 
deposits. 



20 



TABLE 3. - Summary of acid lixiviant costs, advantages, and disadvantages 





Cost 1 




Lixiviant 


Per kg-mole 


Per lb-mole 


Ppn 


i U3O3 paying 2 for 


Advantages and 




(per kg- 


(per lb- 


0. 


051 M solution 3 


disadvantages 




equiv wt) 


equiv wt) 


(0. 


102 N solution) 3 




2 <+• • • • 


$8.65 


$3.92 




6.7 


Very effective in amena- 




(4.33) 


(1.96) 




(6.7) 


ble deposits, restora- 
tion easier than with 
(NHi + ) 2 C0 3 . Not usable 
in deposits with much 
CaC03, not selective 
for U. 




8.33 


3.78 




6.4 


Claimed to be effective 




(8.33) 


(3.78) 




(13) 


for carbonaceous depos- 
its. Not selective 
for U, dissolves Ra, 
requires cationic IX 
resin, difficult 
restoration. 




7.61 


3.45 




5.9 


Claimed to be effective 




(7.61) 


(3.45) 




(12) 


for clayey deposits. 
Not selective for U, 
dissolves Ra, requires 
cationic IX resin. 



^Figures in parentheses expressed in term shown in parentheses in the corresponding 

boxheads. 
2 Assuming $66/kg for U3O3 and neglecting recycling. 
Equivalent to 5 g/1 H 2 SO t+ . 

TABLE 4. - Summary of oxidizer costs, advantages, and disadvantages 





Cost 




Oxidizer 


Per kg-mole 


Per lb-mole 


Ppm U 3 8 
paying 1 for 
0.3 g/1 


Advantages and disadvantages 


2 : 

Texas. . 
Wyoming 


$3.40 
5.10 


$1.55 
2.33 


0.48 
.72 


Cheap. Must be injected 
downhole, can cause gas 
blockage near injection 
wells. 




43.48 


19.72 


12 


Can be added to lixiviant 
above ground. Expensive. 


NaC10 3 ... 


46.97 


21.30 


4.4 


Solubility does not depend 
on pressure. Na can reduce 
permeability. CI can 
reduce ion-exchange resin 
efficiency. 



1 Assuming $66/kg for U3O8 and neglecting recycling. 



21 



When assessing the significance of the chemical costs, it is useful to 
express them in terras of the parts per million U3O8 in solution that pays for 
the chemical costs of a typical strength lixiviant. Accordingly, table 2 
includes the parts per million U3O8 required to pay for 3 g/1 carbonate or 
bicarbonate, a typical concentration. Table 3 lists the parts per million 
U3O3 required to pay for acid molar and normal concentrations equivalent to 
5 g/1 sulfuric acid. The costs of equivalent normalities are included because 
they are comparisons of the costs of obtaining a selected pH. Table 4 lists 
the parts per million U3O8 required to pay for 0.3 g/1 oxygen, which is a typ- 
ical concentration, provided by each of the oxidizers. A value of $66 per 
kilogram ($30 per pound) is assumed for U3O8. 

The parts per million U3O3 listed in tables 2-4 were calculated assuming 
no recycling of the lixiviants, and so are upper limits. Recycling was not 
included because it depends on site-specific factors. Discussions with leach- 
ing company personnel suggest that 60 to 90 percent of the lixiviant can be 
recycled at most sites. The parts-per-million values can be compared with 
the 17 to 200 ppm U3O3 in the pregnant solutions from successful operations. 
The comparisons can help avoid incorrect conclusions. For example, one might 
infer that sodium bicarbonate should not be used because it costs twice as 
much as an equivalent concentration of dissolved carbon dioxide. However, 
when recycling is considered, the cost difference is equivalent to only about 
1 ppm U3O8 and so will have less impact than a very small difference in leach- 
ing efficiency. 

Tables 2, 3, and 4 also summarizes the advantages and disadvantages of 
the various alkaline and acid lixiviants and the oxidizers, respectively. 

METHODS OF TESTING LIXIVIANTS 

The costs, advantages, and disadvantages previously presented provide 
only a general guide for lixiviant selection. To determine the suitability 
for a specific deposit, thorough laboratory and field testing is necessary. 

Laboratory Tests 

Both batch leach tests (sometimes called agitation leach tests) and col- 
umn leach tests are used in selecting the lixiviant. Batch leach tests con- 
sist of placing the ore and lixiviant in a container, often a sealed flask, 
and gently agitating them. Although they do not simulate downhole conditions, 
they can show the relative rate and amount of uranium extraction with tested 
lixiviants and can give an indication of lixiviant and oxidant consumption. 
Obtaining meaningful results from oxidizer consumption tests requires special 
care to avoid oxidizing the ore before the test. 

Column leaching tests simulate field conditions more closely than batch 
tests, but caution must still be used when extrapolating from laboratory to 
field. The contact between ore and lixiviant is more complete than in actual 
in situ leaching. Therefore, for both batch and column leaching, the measured 
consumption of lixiviant and oxidizer and the extraction of uranium should be 
viewed as upper limits of what might be expected in the field. 



22 



Column leaching tests can indicate permeability losses, but to obtain 
meaningful results, water from the formation should be used and the ore should 
be disaggregated and blended. Attempts to use intact cores in hopes of better 
simulating downhole conditions have not been satisfactory. Meaningful compar- 
isons of lixiviants require similar cores, but cores vary considerably in per- 
meability and uranium content. 

Pilot Field Tests 

A pilot-scale field test is conducted before starting commercial opera- 
tion. It is needed not only as an aid to making the final choice of lixiv- 
iant, but also for evaluating well construction and completion techniques and 
for demonstrating restoration procedures. 

Pilot-scale tests can be divided into two classifications. The first 
type is called push-pull, or huff-and-puf f . The lixiviant is injected and 
recovered from the same well. There is some disagreement as to the value of 
push-pull tests. The second type can be called flow-through. The lixiviant 
is injected, flows through the formation, and is recovered from other wells, 
as it is in most commercial operations. Therefore, many consultants prefer 
the flow-through test. 

Problems can occur that render a pilot field test useless as a guide in 
making the final choice of lixiviant. Problems that have occurred include the 
following: 

1. Leaking casings. 

2. Clogging of well screens or nearby formation. 

3. Clogging of formation near a production well. 

4. Reprecipitation of uranium. 

GEOCHEMICAL MODELS 

Geochemical models applied to in situ uranium leaching can assist in 
lixiviant selection. The models can be divided into two major categories. 
The first type of model, the equilibrium approach, is useful for describing 
numerous interactions of a complex system of aqueous species and solid phases. 
This type of model can be used to determine the reactions that are likely to 
occur within a given system, but it gives no information concerning the rates 
of the reactions. 

The second type of model, the kinetic model, simulates the progress of 
kinetic reactions as a function of time and location. Because kinetic models 
cannot be used in selecting a lixiviant unless pertinent reaction rates are 
first determined through laboratory experiments, this report will concentrate 
on equilibrium modeling. 



23 



As of 1980, probably the most useful model for in situ uranium leaching 
is an updated version of the equilibrium program WATEQF. 7 The program 
requires as input a relatively complete chemical analysis of the solution of 
interest. A table of thermodynamic data for all reactions modeled by the pro- 
gram must also be read into the computer. WATEQF computes the state of satu- 
ration of the solution with respect to various minerals and amorphous solid 
compounds. The program compares the activity product of the ions involved in 
the appropriate reaction with the thermodynamic equilibrium constant for that 
reaction, and calculates the log of that ratio, which is termed the saturation 
index (S.I.). If S.I. is significantly less than zero, the solution is under- 
saturated with respect to that mineral. If S.I. is close to zero, then the 
reaction is close to equilibrium. If S.I. is greater than zero, the solution 
is supersaturated with respect to that mineral. This does not necessarily 
indicate precipitation, because solutions can remain supersaturated with 
respect to some minerals for a long time. Thus, the program is useful for 
predicting trends in solubility with changes in lixiviant composition, but 
cannot necessarily predict the concentrations that will be measured. 

As of 1980, at least two companies are using WATEQF (as modified by 
Runnels) to assist in determining how the lixiviant composition should be 
changed to improve leaching. One company uses it to help select the most cost- 
effective lixiviant composition for dissolving the uranium minerals. The cost 
of a solution providing a given pH and Eh can be estimated, and the solubili- 
ties of the minerals can be predicted with WATEQF. Thus, for a given lixiv- 
iant cost, the program can help select the combination of pH and Eh maximizing 
solubility. Judgment is still required for balancing cost versus solubility, 
however. 

WATEQF has also been used to predict whether solubilities will increase 
or decrease with changes in carbonate concentration, pH, or Eh. It is espe- 
cially helpful in determining the probable cause and suggesting a cure when 
pilot tests are yielding much less uranium than expected. This company also 
uses WATEQF to predict the relative amounts of uranium species. Uranium as a 
monocarbonate complex will not load on anionic exchange resins, and so is 
undesirable. WATEQF predicts what fraction will be in monocarbonate, dicar- 
bonate, and tricarbonate complexes. The program has also been used to pre- 
dict fouling from minerals precipitating in pipes and to study restoration 
geochemistry. 

SUMMARY 

The selection of a lixiviant for in situ mining usually proceeds through 
three phases. First, general advantages and disadvantages of lixiviants are 
considered. These general considerations include technical, economic, and 
environmental factors. Currently, restoration of ground water quality is 
causing a movement away from ammonium carbonate-bicarbonate toward sodium 

'Runnels, D. D., R. Lindberg, S. L. Lueck, and G. Markos. Applications of 
Computer Modeling to the Genesis, Exploration, and In Situ Mining of 
Uranium and Vanadium Deposits. New Mexico Bureau of Mines and Mineral 
Resources, Socorro, N. Mex. , Memoir 38, 1980, pp. 355-367. 



24 



bicarbonate and dissolved carbon dioxide. The cost of the oxidizer should 
be carefully considered, because it can exceed the cost of all the other 
chemicals. 

Second, lixiviants that seem promising are tested with ore (cores) from 
the site to be leached. Laboratory batch and column leaching experiments mea- 
sure leaching effficiency, consumption, and effect on permeability. These 
tests can be misleading if not conducted and interpreted with care. 

Third, a pilot-scale field test is conducted. Proper well construction 
is vital to the success of this test. The test can be either the push-pull 
or the flow-through type. The former is cheaper, but the later simulates 
full-scale conditions more closely. 

Computer modeling of the geochemistry can aid in the selection pro- 
cess. Such models are being used by at least two leaching companies to pre- 
dict changes in solubilities associated with possible changes in lixiviant 
composition. 



25 



ADVANTAGES OF USING A CHLORIDE PREFLUSH BEFORE CARBONATE 

IN SITU LEACH MINING 

by 

Daryl R. Tweeton 1 



ABSTRACT 

Laboratory experiments indicate that the consumption of potassium 
carbonate-bicarbonate can be greatly reduced if the ore is conditioned with 
potassium chloride before leaching. Because potassium chloride is relatively 
cheap, the cost of using potassium carbonate-bicarbonate is reduced to the 
extent that substituting it for ammonium carbonate-bicarbonate appears feasi- 
ble. This substitution facilitates postleach restoration of ground water qual- 
ity. Flushing the ore with a chloride solution before leaching also helps to 
reduce permeability losses from calcium carbonate precipitation. 

INTRODUCTION 

The restoration of ground water quality to the criteria set by regulatory 
agencies is difficult or impossible following leaching with ammonium carbonate- 
bicarbonate. Alternative lixiviants such as sodium carbonate-bicarbonate, dis- 
solved carbon dioxide, and sulfuric acid have limitations resulting in their 
use not being feasible in many deposits. (These limitations are discussed in 
the paper titled "Selection of Lixiviants for In Situ Leach Mining.") Potas- 
sium carbonate-bicarbonate is environmentally and technically attractive, but 
has been considered too expensive to use. In late 1980, 1 kg-mole of potas- 
sium bicarbonate cost $31, whereas 1 kg-mole of ammonium bicarbonate cost $8. 

Researchers at the University of Texas at Austin, funded through a Bureau 
of Mines contract, have developed a procedure that promises to greatly reduce 
the cost of using potassium carbonate-bicarbonate. The researchers primarily 
responsible for developing the procedure are Terry Guilinger, Michael Breland, 
and Robert Schechter. 

THE CHLORIDE PREFLUSH 

The procedure consists of flushing the ore with potassium chloride before 
leaching with potassium carbonate-bicarbonate. In most ore, much of the con- 
sumption of lixiviant is by cation exchange. Therefore, satisfying the cation 
exchange sites with potassium from the potassium chloride before leaching 
reduces the consumption of potassium carbonate-bicarbonate during leaching. 
Because potassium chloride is relatively cheap, $5 per kilogram-mole in late 
1980, the cost of using potassium carbonate-bicarbonate is reduced. 



Research physicist, Twin Cities Research Center, Bureau of Mines, Minneapolis, 
Minn. 



26 



In laboratory experiments, the consumption of potassium carbonate- 
bicarbonate was reduced 83 percent. If the same reduction occurred when in 
situ leaching with potassium bicarbonate, and if it is assumed that any 
decrease in bicarbonate consumption requires an equal increase, on a molar 
basis, of the chloride preflush, then the effective cost of potassium bicarbo- 
nate is (0.17)($31) + (0.83)($5) = $9 per kilogram-mole. Thus, the effective 
cost of the potassium bicarbonate would be similar to the $8 per kilogram-mole 
cost of ammonium bicarbonate. This calculation suggests that substituting 
potassium carbonate-bicarbonate for ammonium carbonate-bicarbonate would be 
economically feasible. Of course, a thorough site-specific economic compari- 
son should include not only material costs of the chemicals, but also factors 
such as freight, labor, and equipment for handling the chemicals, and the pos- 
sible effects of chloride on the loading ability of resins. 

The laboratory experiments indicated that an additional benefit was bet- 
ter maintenance of permeability. The permeability was often nearly twice as 
high during leaching following the chloride preflush as it was without the 
preflush. Maintaining permeability during laboratory tests was attributed to 
a reduction in calcium carbonate precipitation. Ammonium or potassium in high 
concentrations tends to drive calcium off clays by ion exchange. The calcium 
may be transported some distance in a supersaturated condition, but causes 
clogging when it precipitates. Calcium chloride is much more soluble than 
calcium carbonate, so calcium can be removed by the chloride preflush. This 
benefit could also be obtained if a sodium chloride preflush preceded a sodium 
carbonate-bicarbonate lixiviant in deposits where the sodium did not cause 
excessive clay swelling. The same experiments showed that the chloride pre- 
flush did not reduce the uranium recovery. 

The calcium-rich solution produced during the chloride preflush may also 
be useful during restoration. Depending on the postrestoration limits set for 
potassium, it may be advisable to inject a solution of high ionic strength 
during part of the restoration flushing to facilitate removal of potassium by 
ion exchange. To avoid creating new restoration problems, the primary cation 
in the high-ionic-strength solution should be harmless and found in fairly 
high levels in natural ground water. Thus, the calcium-rich solution produced 
during the chloride preflush appears ideal for that purpose. A patent disclo- 
sure on the chloride preflush method has been filed in the Solicitor's Office, 
U.S. Department of the Interior, Washington, D.C. 



27 



RESTORING GROUND WATER QUALITY FOLLOWING IN SITU LEACHING 

by 
Daryl R. Tweeton 1 



ABSTRACT 

To assist mining companies in planning for restoration of ground water 
quality following in situ uranium leaching, the Bureau of Mines funded the 
preparation of two reports. "Restoration of Groundwater Quality After In Situ 
Uranium Leaching" primarily describes options for disposing of the waste solu- 
tion from restoration and provides engineering cost estimates. "Analysis of 
Groundwater Criteria and Recent Restoration Attempts After In Situ Uranium 
Leaching" summarizes restoration attempts, presents an empirical equation pre- 
dicting the amount of ground water flushing required, and presents State and 
Federal permit requirements. This paper summarizes some of the information 
from those reports. 

INTRODUCTION 

When planning in situ uranium leaching, the restoration of groundwater 
quality is one of the areas of greatest uncertainty. To assist mining compa- 
nies in such planning, the Bureau of Mines has funded the preparation of two 
reports. 

The first report was completed in 1979 by Ford, Bacon, and Davis Utah, 
Inc., and is titled "Restoration of Groundwater Quality After In Situ Uranium 
Leaching." It primarily describes the various options for dealing with the 
large volumes of waste solution from restoration and presents engineering cost 
estimates. It also describes related geology, geochemistry, regulations, and 
several restoration attempts. 

The second report was completed in 1981 by Resource Engineering and 
Development, Inc., and is titled "Analysis of Groundwater Criteria and Recent 
Restoration Attempts After In Situ Uranium Leaching." Volume I contains sum- 
maries of restoration attempts within the last 5 years, capital costs of dis- 
posal systems reported by operators, and an empirical equation that provides a 
guide as to the amount of ground water flushing required to meet restoration 
criteria. Volume II contains in situ leaching permit requirements, including 
restoration requirements, for Texas, Wyoming, New Mexico, Utah, Montana, Colo- 
rado, and South Dakota, and Federal requirements. 

This paper summarizes some of the information in those reports. Those 
who want the complete contract reports should contact Daryl Tweeton at the 
Bureau of Mines in Minneapolis, Minn., 612-725-3468. 

Research physicist, Twin Cities Research Center, Bureau of Mines, Minneapolis, 
Minn. 



28 



DISPOSAL METHODS 

The waste solution from in situ leaching and from postleach restoration 
can be disposed of in either a deep disposal well or an evaporation pond. 
Generally, deep disposal wells have been used in Texas and evaporation ponds 
in Wyoming. 

Deep-Well Disposal 

Injection of waste through a deep well into a zone that does not contain 
useful water offers the advantage that the waste is completely removed from 
the biosphere. Examples of disposal of waste solutions similar to that from 
an in situ leaching operation occur in a report on uranium mills in New Mex- 
ico 2 and in Union Carbide's permit for the Palangana Dome uranium plant. 3 

A deep-well disposal system includes equipment required to concentrate 
and condition the waste stream for injection and to transport the waste solu- 
tion from the mining site to the injection well. Deep-well disposal is 
limited to waste solutions that will not plug the injection zone by the pre- 
cipitation of solids in reactions between the solution and the matrix of the 
host aquifer. In some cases, precipitation can be prevented or reduced by 
adjusting pH or adding retardants such as sodium hexametaphosphate for calcium 
sulfate. 

Summaries of the capital and operating costs are presented in tables 1 
and 2. Capital costs are calculated for variations of each of the primary 
factors affecting a disposal well: injection rate, well depth, and drilling 
difficulty. The operating cost estimate is divided into the direct costs of 
power, chemicals, and operating and maintenance, and a concluding summary of 
operating costs that includes overhead expenses and fixed charges. Power 
costs are calculated for an average wellhead pressure of 260 psi. Chemical 
costs include acid for pH adjustment, polyphosphate to retard calcium sulfate 
deposition in the injection zone, and copper sulfate to control bacteria and 
fungi. Chemical additions are proportional to flow rate. 

TABLE 1. - Deep-well disposal capital costs versus well depth 

and rock type, mid-1978 dollars 







Well 


capacity 




200,000 gpd 






1 million gpd 




(single well) 


(2 wells 


at 500,000 gpd each) 


5,000-ft well depth: 












1,202,000 






3,485,000 


Difficult rock. 


1,345,000 






3,761,000 


10,000-ft well depth: 












1,538,000 






4,148,000 




2,083,000 






5,220,000 


1 5,000-ft well depth: 












2,001,000 






5,069,000 




3,200,000 






7,440,000 



2 Lynn, R. D., and Z. E. Arlin. Anaconda Successfully Disposes Uranium Mill 
Waste Water by Deep Well Injection. Min. Eng. , v. 14, July 1962, pp. 49-52, 

3 Union Carbide Corp. Permit for Subsurface Disposal of Industrial Waste, 
No. WDW-134. Texas Water Quality Board, Austin, Tex., Sept. 22, 1976. 



29 



TABLE 2. - Operating costs for deep-well disposal system 
(5,000-ft well of average drilling difficulty) 



Capacity 



200,000 gpd 



Cost per 
1,000 gal 1 



Pet of 
total 



1 million gpd 



Cost per 
1,000 gal 1 



Pet of 
total 



Direct costs: 

Power (injection pump, transfer 

pumps , ancillary loads ) 

Chemicals: 

pH adjustment. 

Sodium hexametaphosphate. 

Copper sulfate 

Operating and maintenance: 

Operating labor 

Operating supervision (15 pet of 

OL) 

Maintenance and repairs (1 pet of 

TCI) 

Laboratory charges (10 pet of OL). 
Total direct costs 

Overhead costs: 

Plant overhead (60 pet of O&M) 

Administrative (15 pet of O&M) 

Total overhead 

Total direct and overhead 

costs 

Fixed charges: 

Sinking fund payment (8 pet, 10-yr 
life) 

Interest (10 pet, 50-50 debt-equity) 
Insurance, taxes, miscellaneous 
(2.5 pet) 

Total fixed charges 

Total operating costs 

Neg Negligible. 

0L Operating labor. 

O&M Operating and maintenance. 

TCI Total capital investment. 

^id-mS dollars. 



$0.13 

.33 
.06 

.01 

.09 

.01 

.20 
.01 



.84 



.19 
.05 



.24 



1.08 



1.38 
1.00 

.50 



2.88 



3.96 



8 

2 

Neg 

2 

Neg 

5 

Neg 



21 



27 



35 
25 

13 



73 



100 



$0.13 

.33 
.06 
.01 

.04 

.01 

.12 
Neg 



.70 



,10 
03 



13 



,83 



.80 
.58 

.29 



1.67 



2.50 



13 

2 
Neg 

2 

Neg 

5 
Neg 



28 



33 



32 
23 

12 



67 



100 



Solar Evaporation Ponds 

The liquid waste from the leaching operation or from surface treatment 
facilities can be evaporated in a shallow pond with a large surface area. 
As evaporation occurs a sludge remains, which is an important disadvantage 
because there are stringent regulations governing the disposal of the sludge. 



30 



Summaries of capital and operating costs for solar evaporation are listed in 
tables 3 and 4. The cost for disposing of the sludge at the pond site by backfill- 
ing and sealing is included in the estimate. To estimate costs appropriate for in 
situ leaching, an initial grade of 1 percent and a pond lining of 10-mil PVC are 
assumed. Costs change for variation of feed capacity, net evaporation rate at the 
site, grade, and lining. (The contract report discusses available linings.) The 
fixed charges dominate, as would be expected for systems requiring extensive excava- 
tion and little operating labor. Expenses are roughly inversely proportional to thi 
net evaporation rate. 

TABLE 3. - Total capital investment for solar evaporation ponds, 

mid-1978 dollars 



Net evaporation rate, in/yr 



Pond system capacity 



200,000 gpd 



1 million gpd 



40, 
30, 
20, 
10, 



3,010,000 

4,018,000 

6,037,000 

12,108,000 



15,148,000 
20,221,000 
30,380,000 
60,929,000 



TABLE 4. - Operating costs for solar evaporation pond system 

at 40-in/yr net evaporation rate 





Pond system capacity 




200,000 gpd 


1 million gpd 




Cost per 
1,000 gal 1 


Pet of 
total 


Cost per 
1,000 gal 1 


Pet o. 
total 


Direct costs: 


$0.03 


.03 
Neg 

.10 
Neg 


Neg 


Neg 

Neg 

2 

Neg 


$0.03 


.01 
Neg 

.10 
Neg 


Neg 





Operating and maintenance: 


Neg 

Neg 

2 

Neg 


Operating supervision (15 pet of OL) 

Maintenance and repairs (0.25 pet of TCI) 




.16 


3 


.14 


2 


Overhead costs: 

Plant overhead ( 60 pet of O&M) 


.10 
.03 


1 

Neg 


.09 
.02 


1 




Neg 




.13 


2 


.11 


1 


Total direct and overhead costs 


.29 


4 


.25 


4 


Fixed charges: 

Sinking fund payment (8 pet, 10-yr life)... 

Insurance, taxes, miscellaneous (2.5 pet).. 


2.85 
2.06 
1.03 


46 
33 
17 


2.75 

1.99 

.99 


46 
33 
17 




5.94 


96 


5.73 


96 




6.23 


100 


5.98 


100 



Neg Negligible. 

OL Operating labor. 

O&M Operating and maintenance. 

TCI Total capital investment. 

1 Mid-1978 dollars. 



31 



SURFACE TREATMENT 

The waste stream from leaching or from restoration can be sent directly 
to the disposal system (well or pond), or it can first be treated to produce 
two streams. One stream is purified water, and the other is a more concen- 
trated brine carrying most of the dissolved solids. The advantages of the 
second method are that the purified water can be reused, thereby reducing the 
total consumption of water, and the disposal system does not need as large a 
capacity to receive the concentrated brine as to receive the total waste 
stream. 

The surface treatment technique that has been used by in situ leaching 
companies is reverse osmosis. Other treatment methods that are potentially 
useful are described. 

Reverse Osmosis 



Reverse osmosis is a physical means of separating dissolved ions from 
an aqueous stream. An externally applied pressure in excess of the solution's 
inherent osmotic pressure forces water through a semipermeable membrane while 
the dissolved ions are rejected. A solution's inherent osmotic pressure is a 
function of the type of constituents, the ionic characteristics of the dis- 
solved solids, and the relative and absolute concentrations of the solutes. 
A useful rule of thumb for in situ leaching solutions is that 1,000 mg/1 dis- 
solved ions requires approximately 10 psi of applied pressure. 

Tables 5 and 6 summarize capital and operating costs, based on actual 
field systems and experience, as of mid-1978. The sizes of the field systems 
range from 10,000 to 1 million gpd. These reverse osmosis units incorporate a 
flexible mechanical design to maximize water recovery, pertinent instrumenta- 
tion to monitor water quality and flow, a design to minimize membrane fouling 
and scaling, and a membrane cleaning system. These units are skid mounted and 
require only power and piping hookups. These prices do not include site engi- 
neering fees or freight costs. The operating costs include power, operation, 
maintenance, and chemicals. The cost assumptions are power at 2.5 cents per 
kilowatt -hour, membrane replacements required at a rate of 50 percent per 
3 years, and a maintenance requirement from past experience. The estimate is 
based on labor and supervision for round-the-clock and round-the-week opera- 
tion, with the reverse osmosis unit set up and producing at full capacity for 
300 days per year. 



32 



TABLE 5. - Capital costs for reverse osmosis system, mld-1978 dollars 





Capacity (feed rate) 




200,000 gpd 


1 million gpd 


Direct costs: 

Equipment unit 1 (membrane assembly, high- 


139,000 

97,000 
47,000 


597,000 


Peripheral equipment 1 (prefilters, surge tank, 
holding tank, water quality and flow instru- 
mentation, pH control system, transfer pumps, 


358,000 


Other direct costs (20 pet of equipment): Deliv- 
ery costs, installation costs, site improve- 


191,000 




283,000 
14,000 


1,147,000 


Indirect costs (5 pet of direct costs): Engineer- 


57,000 




297,000 
6,000 


1,204,000 




24,000 




303,000 


1,228,000 







^asic cost data for equipment provided by L. J. Kosarek, Director of Systems 
Engineering Research and Development, El Paso Environmental Systems, El 
Paso, Tex. To convert basic data for product-water capacity to feedwater 
capacity, an operation with 85-pct water recovery is assumed. 



TABLE 6. - Operating costs for reverse osmosis treatment 



33 





Capacity (feed rate) 




200,000 gpd 


1 million gpd 




Cost per 
1,000 gal 1 


Pet of 
total 


Cost per 
1,000 gal 1 


Pet of 
total 


Direct costs: 
Power: 


$0.13 

.01 
.06 

.02 

Neg 
.11 


11 

1 
5 

2 

Neg 

9 


$0.13 

.01 
.06 

Neg 

Neg 

.11 


13 


Ancillary (10 pet at feed pump): 
Transfer pumps, booster pumps, 
chemical feeders, instrumenta- 


1 
6 


Operating and maintenance: 


Neg 

Neg 

11 


Operating supervision (25 pet of 

Maintenance material and labor 2 
(includes membrane replacement).. 




.33 


28 


.31 


31 






Overhead costs: 

Plant overhead costs (60 pet of O&M) 
Administrative costs (15 pet of O&M) 


.11 
.03 


9 
2 


.08 
.02 


8 
2 




.14 


11 


.10 


10 


Total direct and overhead 


.47 


39 


.41 


41 






Fixed charges: 

Sinking fund payment (8 pet, 10-yr 

Interest (10 pet, 50-50 debt-equity) 
Insurance, taxes, miscellaneous 


.35 
.25 

.13 


29 
21 

11 


.28 
.20 

.10 


28 
20 

10 




.73 


61 


.58 


58 




1.20 


100 


.99 


100 



Neg Negligible. 

OL Operating labor. 

O&M Operating and maintenance. 

x Mid-1978 dollars. 

Evaluated from information provided by L. J. Kosarek, Director of Systems, 

Engineering Research and Development, El Paso Environmental Systems, El 

Paso, Tex. 



34 



Other Treatment Methods 

Other methods that are described in the contract report include electro- 
dialysis, distillation, ion exchange, foam separation, and freeze separation. 

Electrodialysis can be viewed as a combination of reverse osmosis and ion 
exchange. Ions pass through semipermeable membranes under the influence of an 
electric field. In a typical design, membranes, spacers, and electrodes are 
stacked and held together by end plates much like a plate and frame filter. 
Spacing is usually about 0.1 inch, and spacers are arranged to provide a tor- 
tuous flow path. Stacks range from 0.5 to 2,400 square meters of membrane 
area. A large stock can desalt 150 gpm at 20- to 50-percent salt removal. 
Practical systems use two to six stages. Electrodialysis is more expensive 
than reverse osmosis. A cost estimate from a supplier of electrodialysis 
equipment indicated a total operating cost of $2 to $3 per 1,000 gallons. 

Distillation appears to be prohibitively expensive, four to five times 
the cost of reverse osmosis. The high cost is partly due to the high energy 
requirements. Similarly, ion-exchange treatment costs two to five times as 
much as reverse osmosis. 

Water purification by freezing has not been applied to in situ leaching, 
but the process is claimed to have the potential for low costs, high water 
recovery, and effective contaminant rejection. The basis of the process is 
the principle that when ice is frozen from an aqueous solution of salts, the 
ice is a distinct and purer phase of water. The ice excludes most of the 
salts from its crystal structure. Costs for freeze separation have been esti- 
mated to be 20 to 40 percent greater than costs for reverse osmosis treatment 
for small flow rates, and potentially 20 to 40 percent less than costs for 
reverse osmosis for high flow rates. 

SUMMARIES OF RESTORATION ATTEMPTS 

The results of restoration attempts conducted at five operations in Texas 
and one in Wyoming (Irigaray) are summarized in table 7, prepared in the sum- 
mer of 1980. With the exception of the commercial restoration at Interconti- 
nental Energy Corp.'s Pawnee property, these restoration attempts may all be 
described as relatively small field tests. Several of these companies are, 
however, preparing for large-scale restoration of their mined-out areas. 













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36 



Several different processes have been used in these restoration attempts. 
At the Pawnee site, Intercontinental Energy Corp. treated recycled ammonia 
leach solution abovegrourid by spraying and reverse osmosis. Mobil Oil Corp. 
tested several methods at the O'Hern site for flushing the ammonia from clays, 
including ground water sweeping and cation elution, and also tried a non- 
ammonia leach process. U.S. Steel Corp. has tested ground water sweeping at 
an old in situ leach pilot plant area at the Clay West property. U.S. Steel's 
method of disposing of several pore volumes in a deep disposal well and then 
discharging a treated stream to surface waters appears to have considerable 
merit. Ground water sweeping was also tested by Union Carbide Corp. in a 
small test at the Palangana site. Extensive ground water sweeping and cation 
elution has been done by Wyoming Mineral Corp. at both the Irigaray and the 
Bruni operations. Wyoming Mineral Corp. was testing ground water sweeping of 
an ore zone leached with sodium carbonate-bicarbonate and oxygen. 

The flushing requirements in table 7 indicate how much ground water dis- 
placement is needed to achieve a given degree of restoration at that site. 
This gives operators an idea of the magnitude of the restoration problem and 
provides a basis for sizing solution disposal and treatment facilities and for 
establishing restoration schedules. 

The restoration testing indicates that it is extremely difficult, if not 
economically and technically impossible under existing operating conditions 
and with present restoration technology, to reduce ammonia and aquifer solu- 
tions to the levels set by State regulatory agencies. Complete restoration, 
as defined by these agencies, may require 50 to 100 pore volumes or more if 
an ammonia leach process has been used. Each of the three major companies 
involved in in situ uranium leaching (Mobil, U. S. Steel, and Wyoming Mineral 
Corp.) has changed or is changing its major operations from ammonia to non- 
ammonia leach solutions. 

The nonammonia testing that has been done by Mobil and by Wyoming Mineral 
Corp. indicates that without the adsorption of ammonia by clays, restoration 
is faster and more complete than when ammonia is used in leaching. However, 
it may still be relatively difficult to restore parameters such as uranium, 
molybdenum, total dissolved salts, and conductivity to the levels set by State 
regulatory agencies. 

Ground water restoration appears to be a bigger problem than was thought 
earlier. Field testing has shown that "complete restoration," as defined by 
the State regulatory agencies, has not been attained with reasonable degrees 
of flushing at any of these sites. 

COSTS REPORTED BY OPERATORS 

The intent was to obtain the costs of actual restorations and then com- 
pare these costs with estimates in the earlier study. However, the available 
cost information was primarily capital costs of disposal wells and evaporation 
ponds. Operating costs were not available because the operators had performed 
little restoration of mined-out areas. They felt that it was too early to 
accurately estimate operating costs. 



37 



The capital costs of several deep disposal wells drilled in Texas during 
the past few years are shown in table 8. Possible reasons for the large vari- 
ation in costs follow: Companies having low estimates may not have the same 
ancilliary pretreatment facilities included in their estimates, corrosion- 
proof equipment may be used in the case of the higher estimates, and some 
companies may not include the cost of idle pretreatment equipment that they 
intend to use. Comparing these costs with the estimates in the earlier study 
shows that the estimates are consistent with those for the Union Carbide and 
Wyoming Mineral Corp. wells, and are higher than the others. 

TABLE 8. - Disposal well costs reported by in situ leaching operators in Texas 





Well depth, 


Maximum 


Ancillary 




Company 


ft 


flows per 
well, gpm 


equipment 
cost 


Total well cost 1 


Intercontinental Energy 












4,000 


50 


NA 


$300,000- 350,000 




4,500-5,000 


100-150 


$150,000 


650,000 




5,700 


100 


NA 


1,200,000 




4,500 


200-250 


200,000 


500,000 


Wyoming Mineral Corp. 












6,000 


200 


NA 


2 1, 100,000 



includes ancillary pretreatment equipment, pumps, ponds, etc. 
2 Does not include cost of ponds. 



The capital costs of Wyoming Mineral Corp.'s evaporation ponds are listed 
in table 9. The estimates in the earlier study indicated that a 200,000-gpd 
pond capacity with a 35-in/yr evaporation rate costs $2,878,000, or $37,250 
per acre. The actual field costs per acre are thus higher in this instance 
than the estimates. 

TABLE 9. - Capital costs for WMC's evaporation ponds in Texas and Wyoming 



Site 



Pond size, 
acres 



Pond 
evaporation 
rate, gpm 



Evaporation 
rate, in/yr 



Cost per acre 



Bruni...., 
Lamprecht, 
Irigaray. , 



3.5 
8.9 
12 



6.3 
16 
36 



35 
35 
58 



$65,000 
65,000 
80,000 



38 



CASE HISTORY OF A PILOT-SCALE ACIDIC URANIUM 
IN SITU LEACHING EXPERIMENT 

by 

Michael T. Nigbor, x William H. Engelmann, 2 and Daryl R. Tweeton 3 

ABSTRACT 

The Bureau of Mines, in cooperation with the Rocky Mountain Energy Co., 
constructed wells, analyzed water samples, and otherwise assisted in a pilot- 
scale in situ uranium leaching experiment at the company's Nine-Mile Lake site 
near Casper, Wyo. The experiment is unique in that it is believed to be the 
first pilot-scale operation to complete the leaching-restoratlon cycle using 
sulfuric acid instead of the more common carbonate-bicarbonate leachant. 
This report summarizes activities at that site, including geochemical data 
from startup to restoration and comparisons between laboratory and field 
experiments. 

Sulfuric acid proved to be an effective leachant. Restoration was suc- 
cessful but required extended flushing. The pH was the last parameter to 
return to baseline, requiring about 350 days. This was longer than predicted 
in laboratory simulations. This report is a brief summary of a more complete 
Report of Investigations, entitled "Case History of a Pilot-Scale Acidic in 
Situ Uranium Leaching Experiment," which is expected to be available in early 
1982. 

INTRODUCTION 

The in situ mining operation, known as the Nine-Mile Lake Site, was 
located about 16 km (10 miles) north of Casper, Wyo. Activity centered on a 
roll-front uranium deposit at about the 165-meter (500-foot) depth located in 
the Teapot Sandstone Formation. Permeability is high (0.98 darcy), and the 
content of acid consumers is low (less than 0.1 percent); therefore, the site 
was considered ideal for experimentation with sulfuric acid in situ leaching. 

It has been reported that the common ammonium carbonate-bicarbonate lix- 
iviants are very difficult to flush from the ore body after leaching. ** This 
is because ammonium ions become attached to clays in the formation at ion 

^Mining engineer. 
2 Research chemist. 
3 Research physicist. 
All authors are with the Twin Cities Research Center, Bureau of Mines, 

Minneapolis, Minn. 
Thompson, W. E. , W. V. Swarzenski, D. L. Warner, G. E. Rouse, 0. F. Carring- 

ton, and R. Z. Pyrih. Groundwater Elements of In Situ Leach Mining of 

Uranium. Final report prepared for U.S. Nuclear Regulatory Commission, 

NUREG/CR-0311, August 1978, 173 pp. 



39 



exchange sites and resist removal attempts. Another common lixiviant, sodium 
carbonate-bicarbonate, can reduce formation permeability by swelling clays. 
Sulfuric acid was selected for use at this site because the rate of dissolu- 
tion is higher, 5 because it avoids the problems associated with the above two 
lixiviants, and because the formation is low in acid consumers. 

Laboratory batch leaching tests conducted on ore from Nine-Mile Lake 
indicated that sulfuric acid was a much more cost effective lixiviant than 



15 



-40 



10 - 



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2 5 



LU 
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< 
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DISTANCEJeet 
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FIGURE 1. - Plan view of pattern 2 at Nine-Mile Lake. 



40 
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--20 
-30 
--40 

15 



^erritt, R. C. The Extractive Metallurgy of Uranium. Colorado School of 
Mines Research Institute, 1971, 576 pp. (pp. 68 and 90). 



40 



the two carbonate-bicarbonate lixiviants. Later field results indicated that 
these laboratory tests gave misleadingly favorable results and that sulfuric 
acid offered little cost savings, if any. Potential environmental benefits, 
rather than cost savings, appear to be the major advantages of sulfuric acid. 

THE TEST LEACH PATTERN 

Figure 1 shows a plan view of pattern 2, the subject of this report. It 
is a five-spot pattern with four injection wells at the corners of the pat- 
tern and the production well in the center. In addition to the injection and 
production wells, three observation wells were completed inside the pattern. 
These observation wells, named OB-1, OB-2, and OB-3, allowed for more complete 
geochemical characterization of the leaching process and permitted the lower- 
ing of special equipment without interfering with normal operations. 

THE LEACHING SEQUENCE 

Table 1 lists the average of several samplings of the pattern's ground 
water before leaching. It can be seen that the preleach water was nearly 
neutral in pH, was quite reducing, and consisted primarily of sodium sulfate. 

TABLE 1 . - Average baseline analyses with standard deviation 



Parameter 



Aver- 


±1 a 


age 




6.7 


0.3 


-120 


200 


4,100 


510 


4,300 


550 


0.23 


0.10 


0.5 


0.2 


830 


145 


14 


3.6 


270 


43 


92 


31 


2,510 


244 


46 


4.3 


4.2 


4.0 


<.01 


NAp 



Parameter 



Aver- ±1 a 
age 



pH -log(H+).. 

Eh mV.. 

Conductivity ymho/cm. . 

Total dissolved solids 

ppm. . 

V30 8 ppm.. 

Vanadium ppm. . 

Sodium ppm. . 

Potassium ppm. . 

Calcium ppm. . 

Magnesium ppm. . 

SO n» .ppm. • 

Chlorine ppm. . 

Silicon ppm. . 

Mercury ppm. . 

NAp Not applicable. 



Aluminum ppm. . 

Phosphorus ppm. . 

Fluorine ppm. . 

Iron ppm. . 

Manganese ppm. . 

Molybdenum pph. . 

Arsenic PPb. . 

Selenium ppb. . 

HCO 3 ppm. . 

Dissolved oxygen ppm.. 

Boron ppm. . 

Chromium ppm. . 

Copper ppm. . 

Zinc ppm. . 



0.13 


0.05 


<0.2 


NAp 


0.77 


0.25 


1.07 


0.4 


0.31 


0.18 


0.8 


0.18 


<40 


NAp 


<2 


NAp 


290 


30 


1 


NAp 


0.67 


0.40 


<0.01 


NAp 


<0.01 


NAp 


0.02 


0.02 



The leach solution strength was increased in several steps to minimize 
clogging from reaction products at the start of leaching. After values had 
stabilized at full strength, the injected solution consisted of about 4 g/1 
(grams per liter) of sulfuric acid and 0.10 vol-pct hydrogen peroxide. The 
resulting pH in the injection solution was about 1.8. Flow rates at the pro- 
duction well varied but averaged about 113 1/m (30 gpm). 

Figure 2 shows the injection and production solution pH's during the life 
of the test. The pH dropped gradually to steady values at 50 days. The pH of 



10, 



X 



50 



100 



150 



200 



!50 



300 



400 



450 



500 



Time, Days after start of leaching 

FIGURE 2. - pH versus time for the injection and production well. 



41 



— I— 1 1— l"|T--I 1 1 | 1 1 I 1 | ■ ■ 


i i | i i i i ., i i , , | i i i i | i , i ji , i 

! Restoration 

! ? 


y™' IMJ. 


: \ 




pvy'jj 


.PROD. 

1 


-\ 




1 


a4 


V ; 


\ 




ite^VyJ 




, i . , i 


1 ' ■:-.■••%:! ■ 



550 



600 



the leach solution changed about 0.4 unit during each pass through the ore 
body. At about 350 days, injection of acid was terminated, signaling the 
beginning of restoration. The pH in the production rose linearly with time 
until it reached preleach values 300 days after the start of restoration. 
The pH was the last parameter to return to baseline. 

Figure 3 shows the uranium content of the production solution with time. 
Uranium rose to a peak of 300 ppm and then leveled off at about 100 ppm until 
restoration began. After restoration began, uranium fell to preleach concen- 
trations quickly. 

Figure 4 shows the vanadium content of the injection and production 
solutions with time. Vanadium was present in significant quantities in the 
formation and was mobilized by the leach solution. Vanadium was not extracted 
in the plant and was allowed to recirculate. The only control was a 19-1/m 
(5-gpm) bleed stream to waste (evaporation pond). The extraction plant was 
apparently not harmed by the high vanadium content of the leach solution, and 
vanadium fell to preleach values quickly after restoration commenced. 

Figure 5 shows the iron content of the injection and production solutions, 
Iron plays an important role in the oxidation of uranium to the soluble +6 
state. Figure 6 shows a record of the conductivity of the injection and pro- 
duction solutions. Note that the conductivity fell quickly to near baseline 
conditions after the start of restoration. 



42 



500 



400, 



E 
Q. 
Q. 



300. 



E 
3 



200. - 






100, 



1000. 



900, 

Ol 

E 
D 

•iH 

"D400 . 

C 

^"200. 



\M 



KJ»d 






T 



-Z 



Restoration 



^ 



^JFRQP , 



100 150 



300 350 400 450 500 550 



Time, Days after start of leaching 

FIGURE 3. - Uranium versus time for the injection and production wefls. 



600 




in j. _r~_rZlLW^g!P; 



500 550 



600 



Time, Days after start of leaching 

FIGURE 4. - Vanadium versus time for the injection and production wells. 



43 



500. 



460. 

£ 

a 

Q_300. 



c 

O208. 



iee. - 




"MfA/ s . . P ROD , 



50 100 150 200 250 300 350 400 450 500 550 600 

Time, Days after start of leaching 

FIGURE 5. - Iron versus time for the injection and production wells. 




»: :'!!;! ' ' ' — ' — I — l— " ' — ' ' I ' — ' ■ ' I 



Restoration 



Vrvl 



I 



• I '•■ 'INJ. 

4 : 



50 100 150 200 250 300 350 400 450 500 550 600 

Time, Days after start of leaching 

FIGURE 6. - Conductivity versus time for the injection and production wells. 



44 



Many other parameters were measured in the observation wells in order 
to provide more complete geochemical data than had been previously availa- 
ble. Samples were taken from all of the wells on a daily basis for the first 
70 days of leaching and on a weekly basis for the next 60 days. Detailed sam- 
ples were also taken weekly during the 300-day restoration period. These data 
are too voluminous to include in this summary report. Parameters measured 
were pH, Eh, conductivity, total dissolved solids, bicarbonate, dissolved oxy- 
gen, uranium, vanadium, sodium, potassium, calcium, magnesium, iron, manga- 
nese, molybdenum, silicon, arsenic, selenium, sulfate, chloride, phosphorus, 
fluoride, aluminum, radium, and thorium. In addition, cores were taken from 
the pattern before and after leaching, allowing more complete evaluation of 
the effect of leaching on the formation. 

LABORATORY SIMULATION OF LEACHING 

During the early phases of leaching at the Nine-Mile Lake site, a sepa- 
rate study was funded by the Bureau of Mines to investigate alternative lixiv- 
iants. 6 Sulfuric acid was one of these alternatives. 

Ore from the Nine-Mile Lake site was used during the study on sulfuric 
acid and provided an excellent opportunity to compare laboratory results with 
field results. Such comparisons are vital for determining how to employ labo- 
ratory experiments for predicting field results. 

The tests were conducted in a 120-by 7.6-cm column using blended material 
from Nine-Mile Lake. No effort was made to prevent oxidation of the ore dur- 
ing transport and storage, so the field ore was probably less oxidized than 
the laboratory ore. 

Comparing the results of laboratory and field results indicates the use- 
fulness and potential pitfalls of predictions based on laboratory experiments. 
Probably the most important predictions were that uranium and vanadium would 
leach readily. The general pattern of uranium concentration versus acid 
strength was qualitatively correct, since both field and laboratory results 
showed uranium beginning to increase significantly with 1.5 g/1 acid. 

One potential pitfall is making quantitative predictions of uranium con- 
centration, especially if the ore is oxidized in storage. Also, leach solu- 
tion contact with the ore is generally more complete in the laboratory than 
in the field. Both of these factors can lead to misleadingly favorable 
predictions. 

Simulation of restoration predicted the slowness of the return of pH to 
baseline conditions but failed to predict the degree of slowness. In the 

6 Sundar, P. S. In Situ Leaching Studies of Uranium Ores. Phases I through 
III. BuMines Open File Rept. 140-77, 1977, 392 pp.; available for con- 
sultation at the Bureau of Mines libraries in Minneapolis, Minn., Denver, 
Colo., and Salt Lake City, Utah; at the Central Library, U.S. Department of 
the Interior, Washington, D.C.; and from the National Technical Information 
Service, Springfield, Va., PB 272 717/AS. 



45 



laboratory experiments, restoration was complete in about 13 pore volumes. 
In the field, estimates place the restoration at over 20 pore volumes near 
well OB-3. 

CONCLUSION 

Data collected by the Bureau of Mines show that sulfuric acid proved to 
be a very effective leachant at the Nine-Mile Lake site. The data show that 
3 to 5 g/1 sulfuric acid with 0.10 percent hydrogen peroxide resulted in 80 to 
120 ppm uranium in the production solution. 

Vanadium in solution rose from less than 1 ppm to nearly 800 ppm at the 
midpoint of the operation. The bleed stream apparently stabilized vanadium 
buildup at that point. The operation apparently suffered no ill effects from 
the buildup. 

Restoration, particularly the restoration of pH, to preleach values took 
longer than could be predicted in laboratory experiments. Laboratory experi- 
ments of restoration showed that pH would be within 0.5 pH unit of the pre- 
leach concentration in about 13 pore volumes. Data collected in the field 
suggest that over 20 pore volumes were required to achieve the same results 
near well OB-3. This difference may be due to a number of factors, including 
permeability variations in the ore and leach solution contact with the shale 
confining layers above and below the deposit. 

The data show that sulfuric acid was an effective leachant and that it 
did not mobilize excessive hazardous elements during leaching. Restoration 
took approximately the same length of time as the active leaching phase 
(about 1 year). 



46 



LABORATORY AND FIELD TESTING OF DRILLING FLUIDS TO DETERMINE HOW THEY 

AFFECT SANDSTONE PERMEABILITY 

by 

Jon K. Ahlness, 1 Donald I. Johnson, 2 and Daryl R. Tweeton 3 

ABSTRACT 

The Bureau of Mines conducted laboratory and field experiments to deter- 
mine the amount of permeability reduction in mineralized sandstones after 
exposure to different drilling fluids. Both polymer and bentonite drilling 
fluids were laboratory tested. The bentonite fluids resulted in the most per- 
meability reduction in sandstone cores cut from samples collected at an open 
pit uranium mine. The fluid that resulted in the least permeability reduction 
was an hydroxyethyl cellulose polymer fluid. The greatest permeability reduc- 
tion of the polymers came from guar-gum-based fluids and a synthetic polymer. 
Five polymer fluids were tested with simulated drill cuttings added to repre- 
sent field conditions. The least permeability reduction in these tests was 
obtained from a multipolymer-blend fluid. A field experiment was then under- 
taken to compare two polymer fluids for drilling in situ uranium leaching 
wells. For this test, the polymer fluid with the best (multipolymer blend) 
laboratory results was compared with a commonly used polymer fluid (guar gum) 
that gave poorer laboratory results. When injection rates for the four wells 
drilled with the guar gum were compared with those for the four drilled with 
the multipolymer blend, no statistically significant difference was seen. 

INTRODUCTION 

A common problem for in situ leaching operations is low well injection 
rates. This is caused by low permeability in the formation near the well, 
which can result from the drilling process and is influenced by the type of 
drilling fluid used. The effects of different drilling fluids on sandstone 
permeability were the subject of a study done by the Bureau of Mines. Labora- 
tory tests with several drilling fluids were conducted on sandstone cores. 
Based on the results of these tests, two drilling fluids were selected for 
field testing. The field test consisted of drilling a total of eight injec- 
tion wells at an in situ uranium site and comparing the injection rates of the 
four wells drilled with each fluid. 

Formation damage occurs by two methods. The first is the blocking of 
the pore openings in the wellbore due to a buildup of fine particles on the 



^•Mining Engineer. 
2 Physicist. 
3 Research physicist. 

All authors are with the Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn. 



47 



hole wall. The second method of damage involves drilling fluid filtrate. 
This fluid moves from the well into the formation carrying fine particles 
until they lodge and block pore openings. The filtrate can also affect water- 
sensitive clays in the formation, causing them to swell. The result of these 
occurrences is the narrowing or plugging of pore spaces through which fluids 
may flow, thereby decreasing the permeability. 

The drilling fluids applicable to drilling in situ leaching wells fall 
into two categories, bentonites and polymers. Bentonite is an inorganic gel- 
forming clay colloid, with the predomonant clay mineral being montmorillonite. 
This material is readily dispersible in water and forms a permanent viscous 
suspension which is thixotropic. It controls filtrate loss to the formation 
by forming an impermeable wallcake of clay particles on the wellbore. A poly- 
mer is a molecule formed by the union of two or more identical smaller mole- 
cules, the resulting compound having a molecular weight larger than that of, 
and chemical properties different from those of, any of the original com- 
ponents. Most polymers are derived from organic materials, although some 
synthetic polymers are available. Some common types of organically based 
polymers are guar gum, xanthum gum, carboxymethyl cellulose (CMC), and hydrox- 
yethyl cellulose (HEC), along with various combinations and blends. Polymers 
control filtration loss by forming a network of polymer chains on the 
wellbore. 

Previous related research on drilling fluids showed that guar gum drill- 
ing fluids reduced permeability by a factor of as much as four when injected 
into high-permeability sandstone. Polymer-based drilling fluids such as poly- 
urethane or hydroxyethyl cellulose, with calcium carbonate bridging material, 
were found to be least damaging. 

LABORATORY TESTS 

Sandstone Core Samples 

Sandstone samples were collected from an open pit uranium mine near Bill, 
Wyo. They were taken from newly exposed waste material from the pit floor. 
The quartz sandstone was relatively "clean," with the clay size fraction being 
less than 2 percent. The accessory minerals in the clay size fraction were 
identified as chlorite, muscovite, and sericite. Cores were cut approximately 
2.54 cm (1 inch) in diameter and 2.54 cm (1 inch) long using air as the drill- 
ing medium. The length was limited because the sandstone was quite friable, 
especially in the coarser grain sizes. There was a large variation of grain 
size between cores that resulted in a wide range of initial permeabilities. 

Test Apparatus 

The laboratory drilling fluid test equipment consisted of a permeability 
test cell, two drilling fluid tanks, a brine tank, a breaker tank, and the 
tubing, valves, and fittings necessary to transport and the control fluids 
from the tanks to the cell. All components of the test apparatus were made 
of stainless steel. Nitrogen pressure was used to circulate the fluids to the 



48 



cell. The permeability test cell (fig. 1) accommodated 2.54-cm (1 inch) 
diameter cores up to 10.2 cm (4 inches) in length. 



In Out 




Heat shrink 
tubing 



Hydraulic 
pressure 



Drain 
FIGURE 1, 



Permeability test cell. 



EXPERIMENTAL PROCEDURE 

Drilling fluids were 
laboratory-tested in both 
"clean" and "dirty" (solids 
added) conditions. The 
dirty fluids were tested in 
an attempt to simulate the 
condition in which they are 
used in the field. The flu- 
ids were mixed in 12-liter 

(3.2 gallon) batches with a 
small electric mixer. Mix- 
ing was done for a minimum 
of 1 hour to allow the flu- 
ids to fully viscosify 

(hydrate). Dirty fluids 
were made by mixing Rev-Dust 

(a low-grade bentonite mate- 
rial) into a fully hydrated 
clean fluid. Mixing was 
continued for 30 minutes 
after the addition of the 
Rev-Dust. The dirty fluid 
was then allowed to stand 
overnight to let the excess 
solids settle out in the 
mixing container. The set- 
tled solids were dried and 
weighed to determine the 
remaining solids content of 
the dirty fluid. The fluids 
were then transferred to' the 
drilling fluid tanks of the 
test apparatus. 

Each fluid was used 
for a series of tests over 
a period of 5 to 12 days. 
Formaldehyde was added as a 
preservative to the polymer 
fluids that were suscepti- 
ble to natural breakdown of 
viscosity due to bacte- 
rial actions. Even with 
this precaution, however, 



49 



breakdown with time did occur in some fluids, resulting in decreasing viscos- 
ity from one test to the next. 

Each test was run according to the following format: 

1. Core mounted in permeability test cell. 

2. Initial permeability test. 

3. Circulation of drilling fluid. 

4. Circulation of breaker (if any). 

5. Overnight breakdown time. 

6. Backflush with brine. 

7. Final permeability test. 

A core sample was evacuated in a vacuum chamber in a beaker of 3- 
percent NaCl (sodium chloride) brine. The brine was used to inhibit the 
hydration of any swelling clays which may have been present. The core was 
then mounted in shrink tubing, and the cell was pressurized to 2068 kPa 
(300 psi) for confinement. An initial permeability test was run by forcing 
brine through the core at 345 kPa (50 psi) and measuring the length of time 
required to collect 50 ml (0.013 gallon). 

The drilling fluid to be tested was then circulated past one face of the 
core at 345 kPa (50 psi) for 1 hour to simulate dynamic downhole conditions 
that are present during drilling. After the drilling fluid was circulated, 
the appropriate breaker (if any) mixed in brine was circulated past the core 
face at 345 kPa (50 psi). An overnight breakdown time was then allowed. When 
a breaker was not recommended for a fluid, brine was circulated instead of a 
breaker. For some of the breakerless tests, an overnight rest was used for 
consistency with the breaker tests; in others, the rest of the test followed 
immediately. 

The next step of the test procedure was to force brine through the core 
in the reverse direction (backflush). This backf lushing was done at a pres- 
sure 517 kPa (75 psi) for 10 minutes to simulate well development by pumping. 
At this point a second (final) permeability test was run, which concluded the 
test. 

LABORATORY TEST RESULTS 

Clean Drilling Fluids 

Seven different polymer fluids, a bentonite, and a bentonite-polymer com- 
bination were tested in their clean state. The amount of each fluid used and 
whether or not a breaker was recommended were determined from manufacturer's 
literature. Guar gum fluids from three different manufacturers were tested in 
clean and dirty conditions. 



50 



The test data are summarized in table 1. Test results are given in the 
form of average return permeability. This is the ratio of the final permea- 
bility to the initial permeability, given as a percent, which is the percent- 
age of the original permeability remaining after exposure to the drilling 
fluid. 

TABLE 1. - Summary of clean fluid tests 



Drilling fluid 



Number 


Fann 


viscosity, 


Average return 


of 


cp 


at 300 rpm 


permeability, pet 


tests 








14 




44 


17 


9 




44 


36 


12 




17 


44 


7 




60 


47 


8 




37 


38 


6 




43 


6 


7 




43 


9 


9 




6 


27 


5 




29 


23 


5 




16 


5 



Standard 
deviation, 
pet 



Guar gum 1 

Multipolymer blend 

Xanthum gum 

Hydroxyethyl cellulose 

(HEC) 

Organic ploysaccharide. 

Bentonite-HEC 

Bentonite-HEC l 

Bentonite * 

Guar gum 2 

Synthetic polymer 

*l-day test. 



6 

9 

24 

10 
24 
6 
6 
14 
5 
3 



The highest average return permeabilities were achieved from the HEC 
(47 percent) and the xanthum gum (44 percent) fluids. The xanthum gum 
results, however, were the most variable, with a standard deviation of 
24 percent. The lowest average return permeabilities were obtained from the 
synthetic polymer (5 percent), the bentonite-polymer combination (6 and 
9 percent), the two guar gum fluids (17 and 23 percent), and straight benton- 
ite (27 percent). Two groups of tests were run on the bentonite-polymer 
fluid. Six tests were run with the overnight wait, and averaged 6-percent 
return permeability, and seven were run in one day which resulted in a 
slightly higher average return permeability of 9 percent. 

Dirty Drilling Fluids 

Six different polymer fluids were tested with simulated drill cuttings 
(Rev-Dust) added. The same amount (637 grams; 1.4 pounds) was added to each 
12-liter (3.2 gallon) batch of fluid. This amount should have resulted in 
each fluid having a 5-percent-solids content. However, settlement occured 
when the fluid was allowed to stand overnight, resulting in some variability. 

The test procedures, fluid mixing, and use of breakers were the same as 
for the clean fluid tests. The test data are summarized in table 2. The 
highest average return permeability was obtained from the multipolymer blend 
(43 percent). The lowest average return permeability results were from guar 
gum 3 (6 percent), xanthum gum (7 percent), and the synthetic polymer 
(7 percent). 



51 



TABLE 2. - Dirty drilling fluid summary 



Drilling fluid 


Percent 
solids 


Fann viscosity, 
cp at 300 rpm 


Number 

of 
tests 


Average 

return 

permeability, 

pet 


Standard 
deviation, 
pet 




4.36 
4.91 

3.96 
2.27 
5.00 
2.92 


39 

48 

60 
39 
21 
13 


5 
5 

5 
5 
5 
4 


26 
43 

25 
6 
7 
7 


14 


Multipolymer blend.... 

Hydroxyethyl cellulose 

(HEC) 


6 
16 




5 




2 




4 



FIELD TEST 

Two polymer drilling fluids were compared in the field by drilling eight 
injection wells in a uranium sandstone formation at an in situ leaching site 
and then measuring the injection rate of the wells. The two fluids selected 
were guar gum 1 and the multipolymer blend. The guar gum was chosen because 
it is commonly used, and the multipolymer blend because it gave the best 
results in the laboratory tests. Each fluid was used to drill four wells. 
The well pattern and the fluid used to drill each well are shown in figure 2. 

All the wells were constructed in the same manner, the only difference 
being in the drilling fluids. Each well was started with a 0.14 meter (5-1/2- 
inch) pilot hole drilled to the top of the sandstone formation. This hole was 
then reamed to 0.19 meter (7-3/8-inches) cased and cemented. The ore zone was 
then underreamed to a diameter of 0.28 meters (11 inches), a screen was set, 
and airlifting was done for well development. The viscosity of the underream- 
ing fluids was measured with a Marsh Funnel and ranged from 32 to 40 seconds. 

An injection test was then run simultaneously on all eight wells to 
determine if there was a difference in injection rates between the wells 
drilled with guar gum 1 and those drilled with the multipolymer blend. The 
test was done by injecting ground water at a constant rate of approximately 
19 liters per minute (5 gpm) into each well and monitoring the resulting pres- 
sure heads (water level) in each well. Approximately 150 liters per minute 
(40 gpm) was pumped from the production well during the test. Pressure trans- 
ducers were used for monitoring the head levels in the wells. 



The injection test was started 5 days after completion of 
and was run for 78 hours. The head level increase at the end o 
other wellfield data are shown in table 3. The data show that 
wells have higher head levels (lower injection rates) than the 
outer well. This occurrence was independent of which drilling 
in drilling the well. This indicates that the well pattern or 
geology greatly affected the test results. When the injection 
four guar gum wells are compared with those of the four multipo 
wells, no statistically significant difference can be found. 



the last well 
f the test and 
all the inner 
corresponding 
fluid was used 
the formation 
rates of the 
lymer blend 



52 



TABLE 3. - Wellfleld data and final head increase 



Hole No. 1 


Underreaming 
fluid 


Marsh funnel viscosity, 
seconds 


Final head increase 




Meters 


Feet 


58 


Multipolymer blend. 


33 
32 
35 
33 
33 
34 
34 
40 


24 

48 

10 

19 

6 

5 

20 

8 


78 


59 


157 


60 


Multipolymer blend. 


32 


61 


63 


63 

64 


Multipolymer blend. 
Multipolymer blend. 


19 

15 


65 


67 




25 



^See figure 2. 

KEY 

□ Production wel 
o Injection wells 



64 Guar gum 
o 



58 Multipolymer blend 
o 



63 61 Guar 


62 


59 


65 


o o gum 


D 


o 


o 


Multipolymer 




Guar 


Multipolymer 


blend 




gum 


blend 



60 Multipolymer blend 
o 



66 Guar gum 
o 

FIGURE 2. - Overlapping five-spot well pattern .showing underreaming fluids used. 



53 



CONCLUSIONS 

It was found from the laboratory tests that there were significant dif- 
ferences in the permeability damage caused by different types of drilling flu- 
ids. The HEC and multipolymer blend polymer fluids resulted in the highest 
average return permeabilities; bentonite, guar gum, and synthetic polymers 
resulted in the lowest. When guar gum and multipolymer blend drilling fluids 
were compared under identical field drilling conditions, however, no signifi- 
cant difference could be determined from injection rates for in situ uranium 
leaching wells. 



54 



APPLICATIONS OF GEOPHYSICAL RESISTANCE MEASUREMENTS 
TO IN SITU LEACHING 

by 

Daryl R. Tweeton 1 



ABSTRACT 

Geophysical resistance and resistivity systems were tested to determine 
their applicability for indicating the movement of leach solution. Measuring 
the resistance between wells appeared promising, as well-to-well resistance 
dropped significantly when leach solution replaced ground water. Galvanic 
resistivity measurements using surface electrodes were less reliable, as the 
results were strongly influenced by factors other than the movement of leach 
solution. Audio magnetotelluric measurements were very susceptible to inter- 
ference from power lines. 

INTRODUCTION 

A means of inferring the pattern of underground movement of leach solu- 
tion during in situ leaching would be helpful in at least two different situa- 
tions. The first is in determining if the leach solution moves in the desired 
uniform pattern during injection. The second is in detecting the start of an 
excursion. 

Accordingly, the Bureau of Mines funded a research contract, awarded to 
Westinghouse Electric Corp. , to test the ability of several geophysical mea- 
surement systems to indicate the change in resistance or resistivity as leach 
solution replaces ground water. Details of the tests are in the contractor's 
final report to the Bureau. This paper summarizes that report. Those wanting 
a copy of that report should contact Daryl Tweeton at the Bureau's Twin Cities 
Research Center in Minneapolis (612 725-3468). Results were also published as 



Research physicist, Twin Cities Research Center, Bureau of Mines, Minneapolis, 
Minn. 



55 

an AIME preprint 2 and the full report 3 is available from The National Techni- 
cal Information Service for $14. 

FIELD TESTS 

Field tests were conducted in 1979 at an in situ uranium leaching opera- 
tion in Wyoming. The ore zone was about 80 meters deep and 3 meters thick. 
Figure 1 shows the arrangement of test locations within the site. The most 
promising technique, measuring the resistance between wells, was tested in 
wells GI 20, 21, 22, 41, 42, and 43. The intent was to measure the resistance 
between the center well and each of the six corner wells before leaching began, 
and then daily after the start of injection of leach solution at the corners. 

The probe configuration is shown in figure 2. A known current flows from 
1^ to l2> and the resulting voltage difference between V^ and V2 is measured. 
The configuration is similar electrically to four-terminal arrays used for 
galvanic resistivity with surface electrodes. However, the downhole probes 
have the important advantages that most of the current passes through the ore 
zone. The casing is nonconductive, so current flows only through the screened 
section. Thus the measured resistance depends primarily on factors within the 
ore zone. With surface electrodes, the ore zone is only a small fraction of 
the volume of earth affecting the measurements. 

Figure 3 summarizes the results. The data show the resistance across the 
pattern in two directions instead of showing the resistance between the center 
well and each corner well because the current electrode in the center well 
showed a high resistance to current flow part of the time. Apparently, the 
drawdown was much greater than expected, and the current probe was out of the 
water during pumping. Therefore, resistance between injection wells across 
the pattern were measured. 

Measurements were made on October 20 and 23, before leaching began. From 
October 23 to November 4, the field was being soaked with oxygenated ground 
water. That lowered the resistance somewhat. Injection of leach solution 

2 Kehrman, R. F., A. J. Farstad, and D. R. Tweeton. Use of Resistivity Mea- 
surements To Monitor Lixiviant Migration During In Situ Uranium Leaching. 
Pres. at Fall Meeting, Soc. Min. Eng. , AIME, Minneapolis, Minn., Oct. 22- 
24, 1980, SME Preprint 80-338, 10 pp. 

3 Kehrman, R. F. Detection of Lixiviant Excursions With Geophysical Resist- 
ance Measurements During In Situ Uranium Leaching. (Final Report, Con- 
tract JO188080 with Westinghouse Electric Corp., December 1979, BuMines 
Open File Rept. 5-81, 1981, 156 pp.; available for consultation at the 
Bureau of Mines libraries in Albany, Oreg. , Avondale, Md. , Boulder City, 
Nev. , Denver, Colo., Pittsburgh, Pa., Reno, Nev. , Rolla, Mo., Salt Lake 
City, Utah, Spokane, Wash., Tuscaloosa, Ala., and Twin Cities, Minn., at 
the DOE facilities at Carbondale, 111., and Morgantown, W. Va. ; at the 
National Mine Health and Safety Academy, Beckley, W. Va. ; at the Office of 
Surface Mining Library, South Interior Building, Washington, D.C.; at the 
Central Library, U.S. Department of the Interior, Washington, D.C.; and 
from the National Information Service, Springfield, Va. , PB 81-171324. 



56 





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58 

began on November 5. The site operator estimated that 1 pore volume had been 
injected by November 11. As shown in figure 3, there was a large decrease in 
resistance between wells 20 and 43, but not between wells 22 and 41. These 
results are consistent with the features of the well field, because wells 
20 and 43 were at the same depth, but there was a difference of 6 meters 
depth between wells 22 and 41. 

Other systems were also tested. Galvanic resistivity measurements with 
surface electrodes were made along the line indicated in figure 1. Details of 
the tests are given in the contractor's report. The results showed decreases 
in resistivity of 9 to 14 percent at several locations in the ore zones where 
leach solution replaced ground water. However, there were other changes in 
resistivity, not associated with movement of leach solution, that were almost 
as large. Thus, reliable separation of the effects of leach solution from the 
other effects whould be difficult. This system might be useful in very 
shallow deposits. 

Audio magnetotelluric measurement of resistivity was tested and found to 
be very susceptible to the interference from electromagnetic waves from power- 
lines. The effect from the interference was greater than the effect from the 
leach solution. When the interference was not present, the measured resistiv- 
ities in various parts of the leach field correlated quite well with the known 
distribution of leach solution. Details are in the contractor's report. 

POSSIBLE APPLICATIONS 

As an example of a possible application, consider a seven-spot pattern, 
as was used in the field test. For several reasons, leach solution would 
probably be injected at the corners and produced from the center. Measuring 
the resistance between the center well and each of the corner wells before 
injection and then daily during injection will indicate whether leach solution 
is moving uniformly toward the center. If the resistance between the center 
and one of the corner wells remains high longer than for the other corners, 
then the leach solution injected in that well may not be moving toward the 
center as desired. Conversely, if the resistance drops unusually quickly, 
there may be a hydrologic short circuit. 

Another possible application is in detecting excursions. To detect 
excursions sooner without increasing the number of monitor wells, one could 
periodically measure the resistance between a monitor well and the nearest 
injection well. Also, measuring the resistance between monitor wells may help 
to detect a narrow excursion moving outward between monitor wells. 

The downhole electrode system requires only standard galvanic resistivity 
instrumentation, which is readily available. 



59 



COST AND SENSITIVITIES MODEL FOR IN SITU LEACH MINING 

by 

William C. Larson, 1 George W. Toth, 2 John R. Annett, 3 
and Orin M. Peterson ** 

ABSTRACT 

In situ mining has emerged as a viable alternative to conventional mining 
techniques. This paper presents the results of an assessment of uranium in 
situ leach mining costs through the application of process engineering and 
discounted cash flow analysis procedures. A computerized costing technique 
was developed to facilitate rapid cost analyses. Application of this model 
will generate mine life capital and operating costs as well as solve for eco- 
nomic production in cost per pound of U3O3. Conversely, rate of return may 
be determined subject to a known selling price. The data bases of the cost 
model have been designed to reflect variations in Texas and Wyoming site 
applications. 

INTRODUCTION 

During the past decade, in situ leach mining of uranium has emerged as a 
viable third alternative to conventional underground and surface mining meth- 
ods. The total number of projects planned for the near future or currently 
employing this technique include 17 commercial-scale operations and 12 major 
pilot scale operations. The South Texas uranium district and Wyoming sites 
represent all of the commercial-scale projects and most of the pilot-scale 
facilities. In 1980, it is estimated that approximately 10 percent of the 
total U.S. production of uranium was obtained from in situ mining methods. 
In contrast, in 1975, less than 1 percent of the total domestic uranium pro- 
duction was attributed to in situ mining methods. 

This increasing level of activity in uranium production by in situ leach- 
ing methods has been accompanied by numerous research studies, primarily 
investigating technical aspects of production. Areas of investigation have 
generally focused on leaching chemistry, well field pattern design, solution 
flow characteristics, and extraction plant metallurgy. 

Economics of uranium in situ leach mining have also been addressed at a 
broad level in public literature, and comparative cost estimates of this 

^Supervisory mining engineer, Twin Cities Research Center, Bureau of Mines, 

Minneapolis, Minn. 
Manager of Research Analysis, NUS Corp., Rockville, Md. 
3 Systems analyst, NUS Corp., Rockville, Md. 
^Mathematician, Twin Cities Research Center, Bureau of Mines, Minneapolis, 

Minn. 



60 



method and conventional mining techniques have been made. A more detailed 
assessment of costs, however, has been largely unavailable. 

This report summarizes the results of an in-depth analysis of in situ 
uranium production costs by employing a process engineering approach. This 
approach disaggregates the in situ production process and analyzes each compo- 
nent in terms of its requirements and associated costs. 

The conduct of this analysis effort has required that both a cost analy- 
sis procedure and a cost data base be generated. The cost procedure developed, 
termed a cost model, has been designed to offer the user maximum flexibility 
in specifying site conditions. The cost procedure, or cost model, accepts 
this site information and subsequently sizes both well field and extraction 
plant, determines equipment and manpower requirements, and assigns an appro- 
priate cost from the model data base. This entire procedure has been 
computerized. 

In this method, total capital and operating costs are generated for the 
life of the project. Costs are developed for all project activities from the 
point in time that a decision is made to commence pilot-scale operations 
through production termination and site reclamation. These costs are subse- 
quently entered into a discounted cash flow analysis which solves for the pro- 
duction cost per pound subject to the rate of return identified by the user 
input data. Conversely, the model can solve for the rate of return on equity 
to be realized from a project for a specified sales price per pound. 

The cost model developed under this research effort has been applied to 
typical in situ mining situations encountered in both Texas and Wyoming. Sen- 
sitivity tests were also conducted to identify the degree of cost influence 
exerted by incremental changes in key project parameters. 

COST MODEL FEATURES 

The cost analysis procedure and cost data base from this research effort 
have been developed over a period of approximately 1 year. Activities 
included visiting nine operating projects, making phone contact with many 
other operators, soliciting cost data from manufacturers and vendors, and 
drawing upon project team operating experience and in-house data. 

The cost model that has evolved from this design framework contains the 
following features: 

1. Develops detailed costs (both capital and operating) and requirements 
for any user-specified project condition for the life of the project. 

2. Solves for minimum required sales revenue per pound of U3O8 (produc- 
tion cost) or rate of return on equity. 

3. Contains regionalized data base for both Texas and Wyoming site 
applications. 



61 



4. Allows for cost analysis applications when only minimal information 
is known, as well as for cases in which detailed project data are available. 

5. Accepts and accounts for either static or dynamic site conditions 
throughout project life. 

6. Accepts user-specified capitalization structure options. 

Each of these points is further explained in the following discussion. 

1. Develops detailed costs. — Beginning with the point in time when a 
decision is made to start a pilot plant facility, all capital and operating 
costs are estimated by this model. The categories of costs generated are 
listed below: 

Capital Costs Operating Costs 

Process equipment Well field replacement 

Equipment installation and/or Manpower 

site improvement Chemical (reagent) 

Building Utility 

Initial well field Operating and maintenance 

Permitting supplies 

Pilot plant Makeup water 

Restoration system General and administrative 

Engineering and/or project 

management 
Fixed capital 
Contingency 
Deferred capital 

Operating costs listed above are considered direct operating costs. 
Other noncash costs, such as depreciation and depletion, are also calculated 
in the discounted cash flow analysis (DCF). Royalities and local taxes are 
likewise estimated in the DCF analysis. The costs presented above represent 
those categories computed by submodels dealing with capital and operating cost 
estimates which all feed into the DCF analysis. 

The process analysis component of the model essentially sizes the proj- 
ect. The basic user-specified site conditions are translated into require- 
ments for extraction plant size (gallons per minute feed rate) and well field 
size (number of patterns and well fields) to meet the user-specified produc- 
tion level. Manpower, horsepower, and well field replacements are also 
computed. 

These requirement calculations serve as the basis for appropriate cost 
assignments from the model data base. A simplified overview of the cost model 
process is presented on the following page: 



62 



MODEL 



PROCESS ANALYSIS 



FINANCIAL ANALYSIS 



INITIALIZATION 



SUBMODELS 



SUBMODEL 



User and 
default input 
parameters 



1. Wellfield analysis 

2. Extraction plant 

analysis 

3. Capital cost 

analysis 

4. Operating cost 

analysis 



n 



5. Discounted 
cash flow 
analysis 



MODEL 

DATA 

BASES 



Submodels 1 and 2 above develop requirements and costs for the respective 
categories listed. Submodels 3 and 4 take both capital and operating cost 
components of the well field and extraction plant and generate total costs for 
each of these categories. The DCF analysis of submodel 5 solves for the sales 
revenue per pound of U3O3 or the rate of return on equity. Each of these sub- 
models is further described later in this section. 

2. Solves for minimum required sales revenue per pound of U3O3 or rate 
of return on equity. — The discounted cash flow analysis submodel provide the 
mechanism for either of the above solution options. Solving for one of these 
options requires knowledge of the other as a model input. The DCF analysis 
uses a profit and loss statement structure for financial analysis of the 
project. 

A user solving for sales revenue per pound of U3O3 is interested in 
determining the minimum sales price that is adequate to cover all operating 
costs and capital recovery expenses and to provide a specified rate of return 
on equity invested in the project. In this situation, sales revenue per pound 
assumes an interpretation of economic cost of production. 

A user solving for rate of return on equity will be employing a known 
market price for U3O3 as input to the model. This situation will be testing 
the viability of a project in terms of its rate of return yield at the antici- 
pated market value. 



63 



Either of the solution options can provide valuable planning information 
for property screening or for testing alternative production levels or other 
project design factors for a given ore body configuration. 

3. Contains Regionalized Data Bases. — The distinction between costs 
incurred in Texas and Wyoming project sites has been incorporated into the 
data base of the cost model. The primary variations recognized by the data 
base account for equipment price differences for similar equipment as well as 
for equipment and/or process system preferences typically associated with each 
region. 

A summary of the key data base distinctions for Texas and Wyoming sites 
follows: 

Extraction Process Equipment 

1. Defines ion-exchange system typically employed. 

2. Allows user four options (Upflow fixed bed, Downflow, Upflow Porter, 
Upflow USBM). 

3. Defines cost differences for each ion-exchange system in Texas versus 
Wyoming for each equipment item for three plant sizes (400, 1,000, and 2,000- 
gpm plant feed rates). 

Well Field Equipment 

1. Defines drilling and casing cost differences for each region for 
three depth categories. 

2. Defines surface piping cost differentials for insulated piping 
(Wyoming) versus standard PVC piping. 

Capital Costs 

1. Defines schedule of expenditures for each capital item according to 
Texas versus Wyoming site location. 

2. Defines permitting cost differentials and time involved according to 
region. 

3. Restoration system selection and therefore cost is based on region 
(deep well for Texas versus evaporation pond for Wyoming). 

Operating Costs 

1. Incorporates differentials in chemical reagent costs between regions. 

2. Incorporates preferences for leaching solution between regions (ammo- 
nium carbonate-bicarbonate for Texas, sodium carbonate-bicarbonate for 
Wyoming). 

3. Includes differences in power and labor costs between regions. 



64 



4. Allows for cost analysis applications under a wide range of Informa- 
tion availability conditions . — To accommodate the broadest possible applica- 
tions, the input structure of the cost model has been organized into three 
categories: 

1. Required input. 

2. Optional input (default values). 

3. Calculation override input. 

These three categories which appear in tabular form at the end of this 
paper, represent the range of information availability regarding a uranium in 
situ leach mining project. Category 1 contains the basic input parameters 
that must be known about a project in order to initiate a model run. There 
are 13 input parameters in category 1, organized according to physical, opera- 
ting, and financial characteristics. Examples of these parameters are depth, 
grade, and ore thickness. There is also a series of cost update factors which 
may be used for cost base years other than 1980. 

Category 2 input includes more detailed characteristics of the project 
which may not always be known. These parameters are assigned default values 
in most cases according to the site location. These default values will be 
used by the model calculation procedures unless the user specifies another 
value in the input sequence. Examples of parameters in this category include 
leach solution, pattern, type, and solution grade. 

Category 3 includes those cost and requirement parameters that are calcu- 
lated by the model. If information is available, however, on the specific 
costs of one or more of the parameters included in this listing, the model 
user may input the value when initiating the model run. This procedure will 
then negate any model calculation required for the subject parameter and 
instead use the value established by the user input. 

5. Accepts and accounts for either static or dynamic site conditions 
throughout the project life . — This feature relates to the ore deposit geome- 
try, chemistry, well field design, and anticipated flow rates and solution 
grades. The model user is given the option of specifying constant conditions 
throughout the project life for 10 parameters or of varying the conditions for 
each succeeding set of well field patterns. 

When changing site conditions is more appropriate than using average val- 
ues for the selected input parameters, the model user may specify changing 
values in terms of absolute or percentage values. To further demonstrate this 
option, the following example of ore body depth changes over the life of the 
project is presented: 

Ore body data: 

Depth of well field 1 400 ft. 

Expected change..... 2-pct depth increase for each 

succeeding well field. 
Input requirement structure: Depth 400,0.02. 



65 



This input data reflects an initial well field depth of 400 feet with an 
increasing depth for well field 2 of 408 feet. Succeeding well fields would 
be 416 feet, 424 feet, 433 feet, etc. If specific changes in depth are known 
in terms of absolute values, they may be input as follows: 

Depth = 400, 420, 480, 410 

In this case, the input indicates that well field 1 is 400 feet deep, 
well field 2 is 420 feet deep, and well fields 3 and 4 are 480 feet and 
410 feet, respectively. 

Values for up to 30 well fields may be input in this manner. Other 
parameter inputs that may be varied in a similar fashion include 

Depth of deposit Injection to production well ratio 

Thickness of deposit Injection to production well spacing 

Ore grade Production well flow rate 

Solution grade Monitor well fraction of total wells 

Well field pattern type Recovery or percent of contained reserves 

6. Accepts user-specified capitalization structure options. — The model 
user may indicate any debt-equity capitalization structure for the project 
being analyzed. Further, the length of loan payback as well as the debt ser- 
vicing rate may also be established by user input. 

This flexibility offers obvious advantages for testing the effects of 
alternative project financing arrangements and the sensitivity of rate of 
return or cost per pound of U3O8 to variations in any of the capitalization 
parameters. 

All of the above-mentioned features are indicative of a costing tool 
which has been designed for maximum user flexibility. 

The model will facilitate rapid sensitivity testing of the effect of the 
project parameter changes on cost results for a specific site. It will serve 
a useful function in preliminary screening of properties for economic viabil- 
ity. Alternative well field designs or extraction plant systems may likewise 
be quickly examined. 

The model is not designed to predict key project parameters such as pro- 
duction well flow rate or solution grade based on permeability, depth, or 
other influencing factors. Many parameters, however, have been assigned 
default values based on regional location which may be used or overriden by 
model users. 

The primary value of this model is its ability to quickly translate any 
user-dictated values for such parameters into overall project cost and design 
implications. 



66 



COST MODEL INPUT STRUCTURE 

The input structure of this cost model is organized into three distinct 
categories: (1) required input, (2) default assigned input, and (3) calcula- 
tion override input. 

In progression from 1 to 3, these categories represent increasing levels 
of information availability regarding project conditions. 

Category 1 represents the minimum amount of information required to ini- 
tiate a model run. Category 2 includes default values, or expected values for 
a number of parameters that will be applied in the costing procedure unless 
changed by the user input. Category 3 contains a parameter listing for major 
cost and requirement results that are calculated during a model run. Should 
the model user have specific cost information for a particular cost category, 
that value may be input — thereby negating all model calculation relating to 
that category and instead applying the input value. 

Each of the three categories of input is further subdivided into physi- 
cal, operating, and financial parameter groupings. Category 1, however, has 
a fourth subdivision termed a control parameter. This provides the user with 
the option of designating the specific output tables desired. 

A further model input option allows the user to designate only a single 
project life value or multiple values for any of 10 parameters describing ore 
body and well field conditions. This input option allows the more technically 
informed model user to dictate any anticipated changing conditions as mining 
advances through the ore body. 

The parameters included in each of the three input categories are tabula- 
ted at the end of this paper. The corresponding model acronym for each param- 
eter is also presented. Parameters for which multiple values or percentage 
change values may be input are designated by an asterisk. Under the cate- 
gory 2 parameters, the default values assigned by the model are also listed 
for each situation in which they would be applied. 

Most values in category 2 are automatically assigned based on the 
regional location of the project (Texas or Wyoming). Some, however, are 
applied in both cases or are based on ore body characteristics. The values 
used as default assumptions are based on practices or situations most commonly 
observed or reported for Texas or Wyoming projects. 

It must again be stressed that any of these default values may vary from 
site to site, and the model user may respond to such variance by overriding 
these default values as project conditions dictate. 

The purpose of including such values is to enable broad-level analysis to 
be conducted in the absence of detailed technical project information. The 
results of applying the cost model when using the default assumed values must 
therefore be interpreted to have wider degrees of uncertainty — unless, of 
course, the default values coincide with perceived project conditions. 



67 



SUMMARY 

The Bureau of Mines, in conjunction with the NUS Corp., has developed a 
computerized cost model for uranium in situ leach mining. The model is struc- 
tured to handle a wide range of user options, so that the novice or more expe- 
rienced individual can utilize the system. Currently the Bureau is looking 
for cooperators to use and verify the model so that its effectiveness, from 
an industry point of view, can be determined. Future work will be directed 
towards expanding the model's capabilities to other commodities, so that a 
wide range of in situ mining costs can be obtained. 



68 



COST MODEL INPUT STRUCTURE 
Category 1. — Required input parameters 



Physical parameters: 

Depth of deposit (ft) , 

(May be stated as an initial value and percentage increase or 
decrease for each new well field. Conversely, absolute footage 
values for each subsequent well field may be used.) 

Thickness of deposit (ft) , 

(Initial footage value and same as DEPT. ) 

Ore grade , 

(Initial percentage value and same as DEPT.) 

Location of property (Texas or Wyoming)... , 

Operating parameters: 

Annual production of U3OS (lb) , 

Productive life (years ) , 

Financial parameters: 

Sales revenue per pound (dollars ) , 

Rate of return of equity (pet) , 

Debt-financed portion (pet) < 

Debt-servicing rate (pet) , 

Project start year (calendar year) ■ 

Cost base year (calendar year) , 

Cost Update Factors: 

Extraction plant 

Drill and case wells , 

Well field equipment 

Mobil equipment 

Chemical costs 

Power costs 

Manpower costs , 

Restoration equipment . 

Control parameters : Print tables 



Same option as DEPT offers. 



Acronym 



DEPT* 



OTH* 

OGRA* 

LOC 

ANNP 
PDTL 

SRV 

ROR 

DEBT 

DSR 

PSY 

CBYR 

EXPF 
DCWF 
WELF 
MOBF 
CHCF 
PWRF 
MPCF 
RESF 
PRNT 



69 



Category 2. — Default assigned input parameters 



Physical parameter: 

Recovery (decimal ) 

Operating parameters: 

Leachant 

Oxidizer 

Solution grade 

Extraction plant process.. 



Well field pattern type. 



Injection-production well 

ratio. 
Injection-production well 

spacing. 
Production well flow rate... 



Acronym 
REC* 
LEAC 
OXID 
SG* 
EXPP 



Value 



PTYP' 



INPR' 



DIST' 



PWFR' 



Operating schedule (days per OSCH 

year ) . 

Monitor well fraction of MWPT* 
total wells. 
Financial parameters: 

Overhead charge OVHD 

General and administrative.. GNA 
Royalty charge: 

Percent of selling price.. ROYP 

Dollar per pound of charge ROYC 

State taxes STXP 

Percent of selling price.. STXC 

Federal income tax FIT 

Miscellaneous operating MSOE 
expense. 

Acquisition cost ACQ 

Capital cost contingency CCON 

factor. 

Multiple values or percent change values 



0.7. 



Texas - ammonia. 

Wyoming - sodium. 

<200 ft depth - H 2 2 . 

>_200 ft depth - 2 . 

Texas - 50 ppm. 

Wyoming - 80 ppm. 

Texas — upflow continuous USBM. 

Wyoming - downflow. 

Other options (Texas and Wyoming) 

Upflow fixed bed; upflow con- 
tinuous - Porter. 
Texas - 5 spot. 
Wyoming - 7 spot. 
Other option (Texas and Wyoming): 

Line drive. 
Texas - 2 to 1. 
Wyoming - 3 to 1. 
Texas - 50 ft. 
Wyoming - 40 ft. 
Texas - 20 gpm. 
Wyoming - 10 gpm. 
Texas - 350. 
Wyoming - 340. 
0.10 



35 pet. 
5 pet. 








46 pet. 
$0 per pound, 


10 pet. 

may be input. 



70 



Category 3. — Calculation override input parameters 



Physical parameter : None , 

Operating parameters: 

Hourly labor requirements , 

Salaried personnel requirements 

Preproduction development time , 

Extraction plant size. , 

Pattern life , 

Financial parameters: 

Process equipment cost , 

Installation and site improvement cost , 

Building costs , 

Well field costs (allow 1 cost per well field input) , 

Restoration system cost , 

Permitting costs , 

Pilot plant costs , 

Site reclamation costs , 

Engineering project management costs (percent of fixed capital), 
Direct operating costs , 



Acronym 



HLAB 

SALP 

DTIM 

EPS 

PTNL 

PEC 

ISI 

PBC 

TWC 

RESC 

PERC 

PPC 

SRC 

EPJM 

DOC 



71 



BRANCHED BOREHOLES FOR IN SITU LEACH MINING 

by 

William C. Larson, 1 Don W. Dareing, 2 Ed T. Wood, 3 
and Don H. Davidson 4 



ABSTRACT 

In situ leach mining now offers a third viable option along with open 
pit and underground mining methods for the extraction of mineral values. 
Multiple-branch wellbore and horizontal holes, when applied to deep-lying ore 
bodies, have the potential of significantly reducing well costs by reducing 
total footage drilled per acre of well pattern. In addition, horizontal holes 
may increase sweep efficiency. Well completion is a major problem, and the 
wells must be cased to contain leach solutions within the underground portion 
of the production loop. Several drilling and completion concepts are given 
and evaluated. The results show that there is economic incentive to further 
develop these concepts for field application to ore bodies greater than 
1500 feet. Multiple-branch concepts can reduce well costs by as much as 
30 percent when applied to 2,000 foot ore body depths. 

INTRODUCTION 

The process of in situ leach mining provides an opportunity to develop 
resources that are currently uneconomical to mine using conventional surface 
or underground mining techniques. In fact, in situ mining has been demon- 
strated to be a third option when considering the economics of an ore body, 
particularly uranium. In situ mining is being commercially practiced in rela- 
tively shallow deposits (200 to 600 ft). 5 However, mineral deposits of ura- 
nium, nickel, copper, molybdenum, and manganese are known to exist at much 
greater depths. Recovery of these deep-lying minerals (>1,500 feet) by in 
situ mining methods is dependent on the availability of relatively low-cost 
drilling and completion techniques. 

Through its in-house and contract research program, the Bureau of Mines 
evaluated nontypical wellbore configurations such as branch holes (fig. 1) and 
drainholes (fig. 2) for in situ mining of deep deposits. Initial results by 



Supervisory mining engineer, Twin Cities Research Center, Bureau of Mines, 

Minneapolis, Minn. 
Engineering associate, Maurer Engineering, Inc., Houston, Tex. 
3 Engineer, Completion Technology Co., Houston, Tex. 
^Assistant project manager, Resources Development and Operation, TRW Inc., 

McLean , Va . 
5 Larson, W. C. Uranium In Situ Leach mining in the United States. BuMines 

IC 8777, 1978, 68 pp. 



72 




FIGURE 1. - Conceptual production scheme using branched boreholes for in situ mining. 




FIGURE 2. - Conceptual production scheme using horizontal drain holes for in situ mining. 



A 200 's 



200' 




2,000' 





CONVENTIONAL 
WELL BORES 



MULTIPLE-BRANCH 
HOLES 



FIGURE 3. - Placement of conventional wellbores and 
multiple-branched boreholes. 



73 



the Bureau 6 showed that 
there are a number of advan- 
tages when using branch 
wellbore technology, such as 
increasing the efficiency of 
fluid sweep over a well pat- 
tern; reducing the pressure 
gradient in the well pat- 
tern, thus achieving higher 
flow rates per well; and 
finally reducing the total 
footage of overburden that 
must be drilled. 

Conventional wellbores 
are usually placed in a 
five-spot pattern (fig. 3), 
where the center well is a 
producer and the four corner 
wells are injectors. This 
well pattern would sweep a 
given area, say 200 by 
200 feet. In a broad field 
development program, each 
corner injector well would 
be shared with three other 
adjacent sweep areas so that 
the total well cost for a 
given sweep area is the cost 
of one producer and one 
injector. 

Multiple-branch holes 
can be arranged to penetrate 
the ore body in a five-spot 
pattern with fewer well- 
heads at the surface. One 
approach is three injectors 
out of one vertical wellbore 
and three producers out of a 
separate wellbore as shown 
in figure 3; completion of 
these types of injectors 
and producers will be dis- 
cussed later in the report. 



Fluid flow through the ore body would be the same for both conventional and 



6 Larson, W. C. , and R. J. Morrell. In Situ Leach Mining Method Using Branched 
Single Well for Input and Output. U.S. Pat. 4,222,611, Sept. 16, 1980, 
4 pp. 
Morrell, R. J., W. C. Larson, and R. D. Schmidt, Method of In Situ Mining. 
U.S. Pat. 4,249,777, Feb. 10, 1981, 4 pp. 



74 



multiple-branch flow cases. Well costs for one sweep area would be one-third 
the cost of a triple branch injector plus one-third the cost of a triple- 
branch producer. 

This project conducted by Maurer Engineering Inc. , and sponsored by the 
Bureau of Mines Twin Cities Research Center, was designed to assess whether 
petroleum engineering technology related to drilling and completing branch and 
horizontal holes could be adapted to in situ mining to either enhance mineral 
recovery or reduce capital and operating costs. The incentive for evaluating 
this technology evolves from current interest in extending in situ mining to 
depths of several thousand feet below the surface. Since the total allowable 
subsurface investment is fixed within a narrow range, the number of well pat- 
terns in operation at any one time will have to decrease as mining depths 
increase, unless techniques are developed to reduce unit subsurface costs. 

DRILLING AND COMPLETION CONCEPTS FOR IN SITU MINING 

Branched wells have been drilled in the past, but none have been cased 
to allow leakproof and pressuretight commumication throughout the wellbore. 
These, of course, are operational requirements for in situ leach mining. This 
section describes several concepts, generated by the project team, for drill- 
ing and completing nontypical wellbores. 

The incentive for applying new wellbore types to 500-foot ore bodies 
is marginal because a conventional vertical hole that satisfies the require- 
ments of in situ mining can be drilled and completed at a relatively low cost. 
It appears that the new technology would not be applicable above 1,500 feet. 
Therefore, the following concepts are directed primarily at ore bodies located 
at depths of 2,000 feet and beyond. At these depths, the economics for using 
advanced drilling and completing technology look much more favorable. The 
following sections describe three concepts for drilling and completing 
branched boreholes for in situ mining. 

Triple Branch Out of 13-3/8-Inch Casing 

A triple-branch well consists of a vertical protection casing with three 
branches extending into the ore body. A series of parallel rows of producers 
and injectors can be used to develop a five-spot sweep area with less total 
footage drilled than with conventional wells. 

This drilling and completion scheme consists of running large-diameter, 
low-grade steel protection casing containing a drilling template (fig. 4), 
then drilling and completing three branch wells out through the bottom of the 
casing as illustrated in figure 5. The bottom joint of casing contains the 
drilling guide and an internal indexing dog to allow for positive entry into 
the three-branch whipstock. 



75 



Working string 



Indexing dog 




•3/8-in cosing 



Vertical branch guide 



Float collar 



FIGURE 4. - Cementing the 13-3/8-inch casing with 
drilling guide as the first step in branch 
well drilling. 



Indexing collar 



Whipstocks 




FIGURE 5. - Drilling and completing 
branched boreholes through the 
bottom of the casing. 



76 



Tubing hanger 



A guide for the verticle branch contains a float collar and seal bore to 
accommodate an inner tubing string for cementing purposes. Once the protec- 
tion casing is cemented in place, the three branches are drilled starting 
with the vertical hole. In each case, an indexing collar is run on the bit 
(fig. 5). The collar is keyed to orient itself with the internal indexing dog 
in the drilling guide. As the indexing collar lands on the dog, the bit is 

released and enters the 
appropriate branch. After 
the hole is drilled, the 
guide collar is retrieved 
by pulling the bit out of 
the hole. 



The indexing collar 
then is rekeyed to index the 
drilling assembly into the 
second hole. Since the 
second and third branches 
are directionally drilled, 
the conventional drilling 
assembly is replaced with a 
downhole directional drill- 
ing assembly, such as bent 
sub and downhole motor. The 
drilling assembly then is 
run in the hole and rotated 
to locate the indexing col- 
lar on the internal index- 
ing dog, and the bit and 
drilling assembly are 
released into the appropri- 
ate whipstock. After drill- 
ing the first directional 
hole, the bit and guide col- 
lar are retrieved, as in the 
vertical branch. The third 
branch is drilled in the 
same manner as the second; 
that is, the indexing collar 
is keyed to guide the direc- 
tional drilling assembly 
into the proper whipstock. 



Fiberglass 



Cement basket 










FIGURE 6. 



Schematic diagram of branched boreholes 
with casing cemented into place. 



Triple strings of 
fiberglass pipe with a 
triple tubing hanger are 
simultaneously run in the 
hole (fig. 6). Cement bas- 
kets are attached to the 
shoe of each casing string 
to prevent the fiberglass 



77 



pipe from floating as heavy cement is circulated into the annulus. The three 
tubing strings are oriented into the branches by the top of the drilling 
guide. Once in place, the three casing strings are simultaneously cemented. 
The triple tubing hanger is set, cement is reversed out above the hanger, and 
the three branches are perforated. 

Production from a triple-branch well requires a fluid head above the 
branch point. A submersible pump would be set in this area from production 
tubing. The 13-3/8-inch casing allows more space for either a larger pump of 
improvements in pump designs, and we see this as a major advantage. 

Setting 13-3/8-inch casing at relatively shallow depths utilizes stan- 
dard oilfield drilling and cementing techniques. However, as the technique 
is applied to deeper objectives, care must be taken not to exceed collapse 
resistance of the casing. As a rule of thumb, the collapse strength should 
be greater than external hydrostatic forces acting on evacuated casing. 
For example, 13-3/8-inch, 54.5-lb/ft casing has a collapse resistance of 
1,130 psi. Assuming a formation pressure gradient of 0.5 psi per foot, 13-3/8- 
inch, J-55-grade casing could be safely set at 2,260 feet. For applications 
below this depth, stronger casing must be used; 72-lb/ft, N-80-grade casing 
with a collapse resistance of 2,670 psi could extend safe setting depths to 
below 5,000 feet. 

Techniques for drilling branch boreholes are low risk and widely used 
in the oil industry. A conventional drilling assembly would be used for the 
vertical branch, and a downhole motor with a bent sub for the directional 
branches. The rate of deviation (5°/ 100 ft) is within limits of conventional 
directional drilling. 

There is not sufficient oilfield experience with triple fiberglass tub- 
ing strings set at shallow depths to accurately assess related risks. Actual 
field tests in shallow wells are needed to determine failure rate from tangled 
or kinked tubing. Triple-completion equipment such as packers and tubing 
hangers is available from oilfield service companies but in less variety than 
dual -completion hardware. 

A review of relative risk related to the proposed branch design suggests 
that formation integrity is critical. Branch wells should not be attempted in 
areas where caving and washouts are a serious drilling problem. Application 
of branch wells should be limited to well patterns with smaller (50- or 100- 
foot) spacings. The same 5°/ 100 ft deviation rate would allow the protective 
casing to be set closer to the ore body, resulting in shorter branches that 
are less likely to cave in prior to casing. 

Triple Branch Out of 9-5/8-Inch Casing 

Directional drilling techniques can also be applied to triple-branch 
wells with smaller protection casing. The completion scheme consists of 
running 9-5/8-inch casing with an internal indexing dog to orient whipstocks 
toward windows in the protection casing. Branches are drilled and a tubing 
guide is installed to direct fiberglass casing into the branches. A series of 



78 



five-spot patterns is developed by alternative parallel rows of producers and 
injectors. 

Branch wells with smaller protection casing offer several advantages over 
the 13-3/8-inch concept. Small drilling rigs can be used to drill 12-1/4-inch 
holes and set 9-5/8-inch casing. Less pump volume is needed to circulate cut- 
tings, and less rig power is needed to set casing. Potential for extending 
applications to greater depths is also greater with small casing, effectively 
increasing the value of experience gained at shallow depths. 

For completion of branch wells with smaller protection casing (9-5/8- 
inch), the following approach is suggested. Protection casing is set an appro- 
priate distance above the ore body. The bottom joint contains a prefabricated 
float assembly and seal bore for an inner string or stab in cementing, and an 
internal indexing dog to positively locate each branch (fig. 7). Fiberglass- 
filled (or other material) windows are provided as easily penetrated exit 
points for the two directional branches. 

After the protection casing is cemented in place, the vertical 6-inch 
branch is drilled, (fig. 8). A whipstock assembly then is run in the protec- 
tion casing and rotated to seat on the internal indexing dog. When in place, 
the whipstock guides a directional drilling assembly through the premilled 
fiberglass window in the bottom joint of the protection casing (fig. 9). 
After the directional branch is drilled to the appropriate depth, the drilling 
assembly is pulled and the whipstock is retrieved with a whipstock-pulling 
assembly. 

The whipstock assembly then is modified to guide the directional drilling 
assembly into the upper window in the protection casing. The whipstock is run 
in the hole with a running assembly and rotated to land on the internal index- 
ing dog with the whipstock facing the second premilled window (fig. 10). The 
upper branch is drilled directionally to the appropriate depth. 

A triple tubing guide then is installed using the internal indexing dog 
for proper orientation (fig. 11). Once in position, it will guide the three 
branch casing strings into appropriate holes. 

A triple string of fiberglass pipe and a triple tubing hanger then are 
simultaneously run in the hole. Cement baskets are attached to the shoe of 
each casing string to prevent the fiberglass from floating as heavy cement is 
circulated into the annulus. The top of the tubing guide orients the three 
strings into the branches. Once in place, the three casings are simulta- 
neously cemented and the tubing hanger is set. Cement is reversed out above 
the hanger; the three branches are perforated, and the well is ready for 
injection. 

Setting 9-5/8-inch casing utilizes standard oilfield drilling and cement- 
ing techniques, and higher grade casing is available for applications down to 
5,000 feet and deeper. 



,.• Kif 



79 



Fiberglass- &v. : , 
filled window — |fc-,. 



Jf-r, 



?■■•; 




''*& 



i-->.'» 



If 





Fiberglass- 
filled window 



Top cement plug 



9-5/8-in casing 



«&— Indexing dog 



Seal bore 

3ottom cement plug 

—Float collar 



FIGURE 7. - Cementing the 9-5/8-inch casing. 



••/•.& 




*.••* :•■;■ 






•'■ii 



'.■t.fti 






lit 




i^-''" ; ::;f.-vu 



FIGURE 8. - Drilling the first branch. 



80 



Indexing dog 



Whipstock — i& 



Down hole drill 




Ska .• 



Down hole drill 



&■!"• 



Whipstock 



K< 



' K>-. 



Whipstock extension 



mm 



Indexing dog 



1U. 



'sV^v.:-'-;;,--.'-.:-!! 



FIGURE 9. - Drilling the second branch. 



FIGURE 10.- Drilling the third branch. 



81 



Tubing guide 




Running assembly 



dexing dog 



FIGURE 11. - Installing the triple tubing guide before 
installation of fiberglass casing. 



At greater depths, the 
precut windows should be elim- 
inated from the drilling guide 
to reduce risk of collapse 
during primary cementing. The 
drilling procedures then would 
be modified to include a mill 
to open windows in the casing. 
Additional rig time would be 
involved, and well cost would 
go up accordingly. 

The proposed tubing guide 
is essentially the same as was 
used in the 13-3/8-inch con- 
cept. However, it must be 
installed after the casing is 
set and the branches drilled. 
The 9-5/8-inch casing must be 
in good condition to allow the 
guide to be installed because 
the outside diameter of the 
guide utilizes the full inside 
diameter of the casing, allow- 
ing only minimum clearance. 

Once the tubing guide is 
installed, the three strings 
of fiberglass are run as in 
the 13-3/8-inch concept. This 
is the most critical phase of 
the branch completion. The 
open hole section of each of 
the three branches must have 
sufficient integrity not to 
cave or collapse while subse- 
quent branches are drilled. 

At this stage of com- 
pletion, remaining risks are 
essentially the same as in the 
final stages of the 13-3/8- 
inch concept. The triple tub- 
ing hanger, cement baskets, 
and cementing procedures are 
identical to those used with 
the 13-3/8-inch concept. 

Oilfield experience sug- 
gests that a dual-branch well 
would have considerably less 



82 



completion problems than the triple. Additional risk reduction would be 
attained by reducing well spacing to 50 or 100 feet. This would move the 
protection casing closer to the ore body and reduce length of individual 
branches. 



Double Branch Out of 9-5/8-Inch Casing 

A dual-branch well consists of a vertical protection casing with two 

branches exending into the 
III" 



Injection fluid 



3"l/2-in fiberglass 



Inhibited fluid 



9-5/8-in casing- 



Left hand 

safety connections- 



Injection branch 



£-§ 



Si 




Produced fluid 



2-7/8-in fiberglass 



Wireline retrievable 
hydraulic pump 



Tubing hanger 



Production branch 



FIGURE 12. - Dual-branch well system utilizing injec- 
tion and production capabilities. 



ore body. Either triple- 
branch design can be sim- 
plified to a dual-branch 
design. Five-spot leach 
patterns would be developed 
by alternating rows of pro- 
duction and injection wells 
or by completing one branch 
as a producer and one as an 
injector. Risks associated 
with dual-branch wells are 
considered to be less than 
those with a triple, but 
cost incentives are also 
less. 

The proposed procedures 
for drilling and completing 
dual-branch wells are essen- 
tially the same as was 
described for triple-branch 
wells with small-diameter 
casing. Therefore, this 
section is primarily devoted 
to designing a lift system 
to utilize injection fluid 
as the power source for a 
downhole positive displace- 
ment pump. 

One unique application 
of the dual-branch concept 
is to use one branch for 
injection and one branch for 
production, as in figure 12. 
The injection fluid is 
routed through a positive 
displacement downhole pump 
as the power fluid; it then 
is exhausted from the pump 
into the injection branch. 
Produced fluid is routed 



83 



from the production branch into the pump and up the production string, as 
illustrated. 

This dual branch design has several advantages over conventional produc- 
tion systems: (1) The downhole hydraulic pump is wireline retrievable for 
repair, (2) the scheme requires less surface plumbing and requires no downhole 
electrical power, and (3) the positive displacement pump maintains a constant 
ratio of produced fluid to injected fluid. For example, the system shown in 
figure 12 utilizes a dual 9-5/8-inch branch well with 3-1/2-inch fiberglass 
injection tubing and 2-7/8-inch production tubing. 

In reality, operating parameters of the dual-branch system will be in a 
dynamic state. Injection and production pressures will vary with influence of 
adjacent wells and temporary changes in effective permeability. However, the 
critical ratio of produced fluid to injection fluid will remain constant. 

Dual-branch wells apply the same drilling and completion procedures as 
were proposed for triples. Setting 9-5/8-inch protection casing at 1,350 feet 
uses common low-risk drilling procedures. Specialty equipment such as the 
drilling guide, whips tock, and tubing guide are conceptually the same as pro- 
posed for triple-branch wells. Risk associated with specialty drilling equip- 
ment for duals therefore is similar to that discussed for triples. However, a 
dual offers some significant risk reductions in that less time elapses between 
drilling and casing of the first branch — hence there is less chance of losing 
the hole. Also, completions are more common in oil wells, and a wide variety 
of packers and tubing hangers are available with experienced people to install 
them. Additional risk reductions can be gained by reducing well spacing to 50 
or 100 feet, allowing the vertical protection casing to be set deeper, thus 
reducing arc lengths of the branches. 

The pumping system in the dual-branch example is novel. A standard 
positive displacement pump would require metallurgical modifications to 
utilize corrosive leach solutions as power fluids. However, advangages such 
as wireline retrieval and fixed ratio of production and injection fluids 
warrant a further study. 

COMPARISON OF WELL COSTS 
X X PER SWEEP AREA 

Consider that a broad 
O O O O mineral field is to be 

developed by a matrix of 
. . . injector and producer wells 

X X 1 X 2 X 3 X drilled and completed in a 

five-spot pattern as shown 
p. p 2 p 3 in figure 13. At present, 
O O O O the matrix of injectors and 

producers comprises conven- 
tional vertical wells, and 
X X X X X the well cost per sweep area 



is the total cost of one con- 
ventional injector well and 
x = in lector; o = producer. conventional producer well. 



FIGURE 13. - Five-spot field development pattern. 



84 



If the mineral field is to be developed using triple-branch injector 
wells (Ij, T-2* I3) an d triple-branch producer wells (Pj, P2» ^3)* tne well 
cost per sweep area is one-third the cost of a triple-branch injector well 
plus one-third the cost of a triple-branch producer well. This formula was 
used to generate the sweep area cost for both triple-branch cases (table 1). 

TABLE 1. - Well cost per sweep area 



Completion method 



Ore body depth 



2,000 ft 



5,000 ft 



Conventional 

Triple branch out of 13-3/8-in casing. 
Triple branch out of 9-5/8-in casing.. 
Double branch out of 9-5/8-in casing.. 



$181,700 
122,603 
125,924 
172,158 



$384,160 
235,634 
214,106 
291,662 



350 



300 



250 



o 200 



en 
O 

o 



150 



100 



50 




/ 



S ^* Triple branch, 



3 3/8 in 



Triple branch, 
9 5/8 in 



± 



1,000 2,000 



3,000 
DEPTH, ft 



4,000 5,000 



6,000 



FIGURE 14. - Well cost per sweep area using branch 
boreholes for in situ mining. 



The double-branch well 
is costed assuming one 
branch will be an injector 
and the other a producer. 
In this case, the cost of a 
double branch is the same as 
the well costs to sweep one 
area (200- by 200-foot sweep 
area). Drilling costs are 
site specific, and rig rates 
vary with demand. Also, 
distance relative to an 
active oilfield signifi- 
cantly changes the expense 
of equipment rental. For 
comparative purposes each 
well scheme is priced as 
though it would be drilled 
in the Houston area. 

These cost data, also 
plotted in figure 14, show 
there is potential cost sav- 
ings with each wellbore type 
when applied to depths 
beyond 1,500 feet. Also, 
cost savings increase with 
depth. However, other fac- 
tors, such as risk, perform- 
ance, and availability, 
enter into the overall 
evaluation. 

CONCLUSIONS 

Branch well drilling 
can reduce well costs when 



85 



applied to mineral deposits deeper than 1,500 feet. The practical limit for 
number of branches drilled and completed from one vertical wellbore is three. 
The two drilling and completion concepts for triple-branch wells require 
development of specialized completion templates and guides. The logical first 
step in developing branch well completion equipment is to limit initial branch 
wells to include only two hole bottoms. Completion experience gained by 
developing templates and guides for dual-branch wells could be readily 
extended to expertise needed to complete three hole bottoms. Further studies 
will be required to develop the specialize equipment proposed for branch well 
completions and to determine risks related to their use. 



86 



GEOCHEMICAL KINETICS MODEL FOR IN SITU LEACH MINING 

by 

Robert D. Schmidt, 1 Steven E. Follin, 2 Kent A. Peterson, 3 

and Eric V. Level 1 * 

ABSTRACT 

A computer model of in situ leaching chemical kinetics is presented as an 
analytic, predictive tool, useful in determining the leachability and produc- 
tive potential of an undeveloped ore deposit and in the optimal design of an 
operating well field. Some examples of model application are presented. Spe- 
cial emphasis is placed on explaining model usage. 

INTRODUCTION 

Changes in leach site operating conditions (for example, injection well 
pumping rates) will affect the net productivity of a pattern owing to the com- 
plex interactions between the hydrology, mass transport, and chemical kinetics 
of leaching. Such a change generally affects different streamlines in differ- 
ent ways, increasing the production rate of some while decreasing that of 
others. This suggests that the most appropriate level of analysis for a field 
problem involving two-dimensional fluid flow is the individual streamline. 

The uranium leaching computer simulation developed at the Bureau of Mines 
Twin Cities Research Center (TCRC) divides the leachant flow pattern into dis- 
crete hydrologic components (individual streamlines) and then models the chem- 
istry and mass transport for each of these components separately. The model 
then computes the productivity and effectiveness of the entire pattern by sum- 
ming the results from these individual streamlines. This approach permits 
analysis of the contribution of each streamline to the effectiveness and effi- 
ciency of the entire pattern. 5 

The model is presently capable of predicting the impact on stream- 
line productivity of various operator-controlled parameters such as well 

Operations research analyst. 
2 Mathemetician. 
3 Geologist. 
^Mathematician. 
All authors are with the Twin Cities Research Center, Bureau of Mines, 

Minneapolis, Minn. 
5 This modeling procedure utilizes research and modeling work performed at the 

University of Texas at Austin. For a detailed description of that modeling 

work, see — 
Bommer, P. M. , and R. S. Schechter. Mathematical Modeling of In-Situ Uranium 

Leaching. Soc. Petrol. Eng. J., v. 19, no. 6, December 1979, p. 393. 



87 



configuration, pumping schedules, oxidant injection rate, and duration of 
operation, as well as site-dependent aquifer and ore zone parameters including 
aquifer permeability, ore grade (differentiating between oxidized and reduced 
uranium), the presence of other minerals which compete with uranium for oxi- 
dant, and accessibility of in situ uranium to the leach solution. 

In addition to a brief description of the chemical kinetic model, which 
has three constituent models, some examples of the graphic output will be pre- 
sented and discussed. 

MODEL CONFIGURATION 

The kinetic geochemical model is composed of three component models. Two 
of these components, hydrology and mass transport, are computer-based models. 
The third, oxidation rate chemistry, is a laboratory model of the leaching 
process. 

The overall model configuration is illustrated in figure 1. The hydrol- 
ogy and laboratory geochemical models must be run prior to the mass transport 
model, which, in addition to simulating the effects of convection and disper- 
sion, performs the function of integrating hydrologic and geochemical output. 

The hydrology model draws primarily on site-specific well, pumping, and 
aquifer characteristics for input, while the laboratory geochemical model 
involves site-specific ore material and leachant. Additional dispersion char- 
acteristics of the aquifer are input to the mass transport model, and the 
final product is a site-specific chemical kinetic simulation. 

The predictive output from these three models includes the streamline 
flow pattern, the hydraulic head and fluid velocity throughout the aquifer, 
the concentrations of uranium and oxygen in the leach solution along each 
streamline, and the uranium recovered from individual streamlines. In addi- 
tion, the uranium production from individual wells, and for the entire pat- 
tern, is computed. 

Hydrology Model 

The hydrology model assumes two-dimensional steady state flow in a homo- 
geneous aquifer. Anisotropy characterized by discrete zones of differing per- 
meabilities, either naturally occurring or induced by leaching, is permitted. 



88 



Well field 
Pumping rates 



Hydrology 



Ore sample 
Lixiviant 



Chemistry 



Aquifer 
characteristics 



Mass transport 



Site specific 
chemical 
kinetic 
simulation 




FIGURE 1. - Model configuration. 



89 



The fundamental equation describing two-dimensional flow in a homogeneous 
isotropic aquifer without accretion is derived from Darcy's law and from the 
fluid conservation law and is given by Laplace's equation, 

32 * + ii|=.o, (i) 



9x 2 3y 2 

where $ = $(Z) for Z = x + iy (2) 

and $ is specified on the boundary of the region, Z = Z c , by 

*(Z C ) = » c . (3) 

The complex potential function ft = ft(Z) is defined as an analytic 
function whose real and imaginary parts are, respectively, the potential 
function, $ = $(Z), and its harmonic conjugate, the streamline function, 
Y = ¥(Z). 

With the definitions of $ and Y as given, the Cauchy-Remann conditions 

3$ 3Y , 3¥ 3$ ... 

S = 17 and "S = " * (4) 

insure that the real part of ft(Z), $(Z), will satisfy equation 1. 

The hydrology output consists of a streamline flow net along with the 
fluid velocity and hydraulic head values along each streamline. The pattern 
resulting from a typical five-spot pattern and a five-spot with guard wells is 
pictured in figure 2. 

Oxidation Rate Model 

The chemistry model consists of a pressurized column leaching apparatus 
and involves a series of leaching experiments with different injection concen- 
trations of dissolved oxygen. The intent is to determine an empirical rela- 
tion between the oxygen concentration and the rates of uranium and mineral 
(pyrite) oxidation. This ore-specific relation is then incorporated into a 
chemical kinetic expression along with the simulated hydrologic output and 
applied to the field problem. 

The geochemical predictions are based on the assumption that oxidation is 
the rate-controlling step in the uranium leaching process. 

The laboratory apparatus involved in these experiments is shown in fig- 
ure 3. The ore sample is contained in a cylindrical elastic membrane inside 
the stainless steel flow cell at the left of the picture. The confining pres- 
sure of overburden is simulated in the laboratory by pressurizing the annular 
space between the elastic membrane and the flow cell. 



90 





FIGURE 2. - Streamline flow patterns. A, Five-spot leaching pattern; 
B, five-spot leaching pattern with guard wells. 



91 




FIGURE 3. - Laboratory leaching apparatus. 

Mass Transport Model 

The mass transport model accounts for the flow and dispersion of leach 
solution through the aquifer. Only longitudinal dispersion is simulated; 
transverse dispersion (across streamlines) is neglected. 

The mass transport model, of necessity, performs the additional function 
of integrating the hydrology output (flow lines, velocity, and hydraulic head 
along streamlines) and the laboratory chemistry results (uranium and pyrite 
oxidation rates) into a kinetic chemical expression. Thus, mass transport 
modeling is performed subsequent to the hydrology and laboratory chemistry 
simulations. 

The integrated kinetic chemical model involves a numerical solution to a 
system of one-dimensional partial differential equations describing the change 
in uranium and oxygen concentration along streamlines as a result of convec- 
tion, dispersion, and the chemical oxidation processes involved in leaching. 



The basic, one-dimensional, convection-dispersion equations with reaction 
terms are presented below along with the appropriate boundary conditions. 
Note that the curvilinear coordinate system SI = $ + if, used in the hydrology 
model, is again employed to describe two-dimensional flow. Since ¥ is con- 
stant along each streamline, the mass transport equation for each streamline 
reduces to a one-dimensional flow problem with $ as the variable representing 



92 



position along the streamline. For notational convenience, $ has been 
normalized to be zero at the injection well. $ n represents the position of 
the production well and <f> is the porosity. 

For the concentration of uranium in solution along a streamline (C u ), 

a — -+3 — 5^ + R = * — - (5) 

3$ 3$ 2 u y 3t 



with C u < = C u ($,t) 

c u (o,t) = c u 

C u (»,0) = 

9C U 
-3T- ($ n>t) = 

where C u is the uranium concentration (in grams per cubic centimeter) in 
the injected lixiviant. For the concentration of dissolved oxygen along a 
streamline (C ), 

3$ 3$ 2 3t (6) 

with C = C ($,t) 

C o (0,t) = C 

C o (*,0) = 

3C 

<«„,t) = 



3$ 

where C is the oxygen concentration (in grams per cubic centimeter) in the 
injected lixiviant and 6 and p is a stoichiometric constants. For the ura- 
nium concentration in the deposit along a streamline (W u ), 

3W U 

IF" - " R " (7) 

with W u = W u ($,t) 

W u (*,0) = W u (*) 



MMWP 



93 



where W u ($) is the initial concentration of uranium along the streamline. 
Finally, for the concentration of an oxygen-consuming mineral (generally 
pyrite) in the formation along a streamline (W ), 



9W p 

= -R, 



3t ° (8) 

W p = W p (*,t) 

W p («,0) = W p («) 

where W p ($) is the initial concentration of mineral along the streamline. In 
these four expressions the oxidation rate relations R u and R , given by 

R u = R u (C u , C Q , W u , W p ) 

Ro T (c u> C Q , W u , W p ), 

are derived from the laboratory oxidation rate experiments. The longitudinal 
dispersion coefficients a and 3 are derived from fluid flow parameters output 
by the hydrology model. e 

These one-dimensional equations describing the reaction chemistry and 
mass transport are solved for each streamline. The calculation of the ura- 
nium recovery for the two-dimensional well pattern is simply the total uranium 
produced by a radial pattern of streamlines around each injection well. 

MODEL APPLICATIONS 

The remainder of this paper presents the graphical results of using 
the model to simulate a hypothetical five-spot operation. These graphical 
descriptions permit the user to readily interpret the results of a simulation 
and are critical for gaining insight into the attributes of different leaching 
strategies. The model developed at TCRC incorporates a number of computer 
programs capable of graphically representing concentration profiles and his- 
tories for uranium or oxygen, and recovery curves for streamlines, individual 
wells, and the entire pattern. 

Figure 4 shows a series of concentration profiles generated by the model 
which depict the concentration of uranium in solution along the length of the 
laboratory flow cell shown in figure 3. One pore volume of leachant is pumped 
through the cell, and eight concentration profiles are developed at equal time 
intervals. Such a simulation of the laboratory leaching process "tunes," or 
calibrates, the model prior to applying it (with its site-specific parameter 
values and laboratory-derived oxidation rate expressions) to the field prob- 
lem. Discrepancies between the computer-simulated profiles of figure 4 (the 
endpoints only) and the measured uranium concentration in solution discharged 

^Bommer, P. M. A Streamline-Concentration Balance Model for In Situ Uranium 
Leaching and Site Restoration. Ph.D. Dissertation, Univ. Texas, Austin, 
Tpy. . Auoiist- 1Q7Q. ?6^ nn. 



94 



34.5 



E 

Q. 
Q_ 



a 25.9 



< 17.3 



UJ 

o 



o 
o 




8.6 - 



21.0 



10.5 14.0 17.5 

DISTANCE, cm 

FIGURE 4. - Laboratory flow cell uranium concentration profiles 



24.5 27.0 



from the laboratory flow cell can be minimized by manipulating certain pro- 
gram inputs. Very often, measured parameter values are only approximate. 
For example, permeability inputs are frequently the result of an averaging 
process. 

Besides acquainting the user with the dynamics of streamline chemical 
kinetics, the subsequent computer graphics point out the hydrologic and geo- 
chemical differences between interior and exterior streamlines of a five-spot 
pattern. Further, these examples demonstrate the advantage of analyzing 
streamlines individually, and display the simulator's usefulness as a predic- 
tive analytic tool. 

Figure 5 shows a short concentration history (8 days) of two different 
streamlines on a typical five-spot pattern of wells. In each case, the 
streamline under consideration is indicated by a dashed line on the five-spot 
pattern at the upper right of the illustration. Each streamline is considered 
to be the center of a region of the flow pattern that is commonly referred to 
as a streamtube. This short history is specifically intended to show the dif- 
ference in front breakthrough times at the recovery well — approximately 
15 hours for figure 5A versus 30 hours for figure 5B. 

Each concentration history depicted in figure 5 is the uranium concentra- 
tion at the last point on the streamline (that is, the center production well) 
plotted as a function of time. Thus, these histories reflect the contribution 
made by each of the two streamtubes to the total uranium recovered from the 
well. The obvious difference in the magnitudes of the two curves illustrates 
the variability of performance among streamlines of a five-spot well pattern. 
The dissimilar paths of these two streamlines lead to the conjecture that the 
differences shown in figure 5 are a result of (1) the greater areal sweep of 



95 



I79i- 




3 4 5 

TIME, days 



E 

Q. 

Q. 



< 

h- 

L±J 

o 

o 
o 




3 4 5 6 

TIME, days 

FIGURE 5. - Eight-day uranium concentration histories. A, Interior streamline; 
B, peripheral streamline. 



96 

the peripheral streamtube, 7 (2) the lower velocity of leachant in the periph- 
eral streamtube, which allows dissolved uranium to concentrate more than in 
the interior tube where it is flushed from the aquifer relatively quickly, and 
(3) the lower velocity in the peripheral line allowing a longer residence time 
for leachant and, hence, more time for the oxidant to react with uranium. The 
discussion below, involving reduced pumping rates will verify that these con- 
jectures about the effects of path length and fluid velocity are correct. 

Figure 6 shows a pair of longer concentration histories for the same two 
streamlines. These curves reflect the contribution of each streamline over an 
8-week interval of site operation. The curves depict gross changes in recov- 
ery rate. In both figures 6A and 6B the declines are due to depletion of ura- 
nium in the ore deposit as a result of leaching activity. 

Recovery curves like these can be developed for any or all of the stream- 
lines appearing in this pattern. Further, the model is not limited to five- 
spot patterns. Any configuration of wells or pumping rates may be simulated. 
Various summary plots showing recovery histories for individual wells or for 
an entire pattern can also be constructed. 

To illustrate how the model might be used for comparative analysis of 
streamline efficiency, the next example will show the effect of a reduction in 
well pumping rate on uranium recovery from the same two streamlines. 

Recall from figure 5 that the high fluid velocity along the interior 
streamline is conjectured to be partly responsible for the reduced recovery 
rate from this line. In an attempt to improve the uranium recovery rate from 
the interior line, solution injection and recovery rates are cut in half, thus 
decreasing the velocity of leachant in the streamline pattern. The resulting 
recovery rate for the interior streamline is shown in figure 7. Although the 
simulation interval is only 80 hours, the difference between figures 7A and 7B_ 
is apparent. Uranium recovery from this streamline increases when solution 
velocity is decreased. Of course, the velocity along the peripheral stream- 
line also decreases when pumping rates are cut; the impact of this new pumping 
rate on the peripheral line is shown in figure 8. In contrast to the interior 
line, the new pumping schedule has had a negative impact on the uranium recov- 
ery from this peripheral streamline. It appears that this negative effect far 
outweighs the slight improvement in recovery achieved by the interior line. 
As a result, total recovery from these two streamlines over the 80-hour period 
has declined. 

The results shown in figures 7 and 8 confirm the previous conjecture con- 
cerning the roles played by the streamline path length and the fluid velocity. 
Furthermore, these simulations evidence the variability in streamline perform- 
ance that can be expected when pumping rates or other parameter values are 
manipulated by the operator. 



'The amount of uranium accessible to the leachant being proportional to the 
area swept. 



97 








3 4 5 

TIME, weeks 




FIGURE 6. 



I 2 3 4 5 6 

TIME, weeks 

Eight-week uranium concentration histories. A, Interior streamline; 
B, peripheral streamline. 



8 



98 



EI.3XI0 5 






o 


4 




o> 






gl.OXIO 5 


— 




or 






LU 






O6.7XI0 4 






o 






LU 






* 4 

^ 3.4X10 






=> 






2 






< 




1 ( 


% c 


) 


10 





30 40 50 
TIME, hours 






.3XI0V 



Si.oxio 5 

or 

LU 

S 4 

g 6.7X10 

LU 

or 

^ 3.4XI0 4 

ID 



< 

or 



B 







10 



20 




30 40 50 
TIME, hours 

FIGURE 7. - Uranium production graphs for interior streamline. A, Full injection rate 
(15 gpm); B, halved injection rate (7.5 gpm). 



99 



tn 



a 

L±J 

or 
lu 
> 

o 
o 

LU 
QT 



1.3X10° r- 



1.0X10* 



6.7XIGT - 



3.4X10 



< 
or 



A 



10 20 30 40 50 

TIME, hours 




E 
o 



1.3X10° i- 



.0X10^ 



Q 
LU 

or 

LU 

> 

O 4 

O6.7XI0 4 

LU 

or 



3.4X10 



< 
or 

Z> 



B 







10 



20 30 40 50 
TIME, hours 




FIGURE 8. - Uranium production graphs for peripheral streamline. A, Full injection 
rate (15 gpm); B, halved injection rate (7.5 gpm). 



100 



Insights into those chemical and hydrologic processes that affect site 
specific leaching effectiveness are not often disclosed by the simulated pro- 
duction history of an entire well pattern. Such underlying mechanisms are 
often revealed, however, by a comparative analysis of individual streamline 
performance. 

CONCLUSIONS 

The kinetic uranium leaching model developed at TCRC has been briefly 
described, and several examples of model applications have been presented. 
Examples showing the effects of competitive oxidation of pyrite, various oxi- 
dant injection rates and rate functions, different well configurations 
(including guard well patterns), lixiviant pH and carbonate concentration, 
permeability loss around injection wells, and zones of differing ore grade 
will be presented in future publications, which will also deal with model 
development in more detail. A user-oriented program, with laboratory instruc- 
tion manual, is also planned. 

The examples presented illustrate how a streamline-by-streamline analysis 
can provide valuable insights into the factors affecting uranium production. 
Combining these insights with the simulation results for the entire pattern 
results in better design of a uranium leaching operation. 

To date, onsite calibration or verification of this model has not been 
attempted. Potential users are reminded that this is an important step in the 
"site validation" process. Release of this model is at present contingent 
upon some involvement by TCRC in this "site validation" process. 



101 



APPENDIX. --BIBLIOGRAPHY OF BUREAU OF MINES IN SITU MINING PUBLICATIONS 

1. Amell, A. R. , and D. Langmuir. Factors Influencing the Solution Rate of 

Uranium Dioxide Under Conditions Applicable co In Situ Leaching (Final 
Report, Contract H0272019 with the Pennsylvania State University, 
BuMines Open File Rept. 84-79, Nov. 20, 1978, 126 pp.; available from 
the National Technical Information Service, Springfield, Va. , 
PB 299 947/AS. 

2. Brinckerhof f , C. M. Assessment of Research and Development Needs and 

Priorities for In Situ Leaching of Copper. Final Report, Con- 
tract J0166036, July 26, 1976, 5 pp.; available for consultation at 
the Twin Cities Research Center, Bureau of Mines, Minneapolis, Minn. 

3. Buma, G. , J. R. Riding, L. Downey, and T. D. Chatwin. Geochemical 

Arguments for Natural Stabilization Following In Situ Leaching of 
Uranium. Proc. New Orleans Symp. , Soc. Min. Eng. , AIME, New Orleans, 
La., Feb. 18-22, 1979 (pub. as In Situ Uranium Mining and Groud Water 
Restoration, ed. by W. J. Schlitt and D. A. Shock), pp. 67-85. 

4. Chamberlain, P. G. Evaluating Ore Bodies for Leaching With Permeability 

Measurements. Proc. New Orleans Sympos., Soc. Min. Eng., AIME, New 
Orleans, La., Feb. 18-22, 1979 (pub. as In Situ Uranium Mining and 
Ground Water Restoration, ed. by W. J. Schlitt and D. A. Shock), 
pp. 7-22. 

5. . Field Permeability Methods for In-Place Leaching. Min. Cong. J., 

v. 64, No. 9, September 1978, pp. 22-25. 

6. . In-Place Leaching Research at the Seneca Mines, Mohawk, Mich. 

Pres. before the Annual Spring Tech. Meeting of Upper Peninsula 
Section, AIME, Michigan Technological Univ. at Houghton, Mich., 
Apr. 21, 1977; available from Twin Cities Research Center, Bureau of 
Mines, Minneapolis, Minn. 

7. Chamberlain, P. G. , and W. C. Larson. Leaching Bibliography — Non-Uranium 

and Non-Copper. Available from authors at Twin Cities Research Center, 
Bureau of Mines, Minneapolis, Minn.; continuous updating. 

8. Chamberlain, P. G. , and M. G. Pojar. The Status of Gold and Silver 

Leaching Operations in the U.S. Pres. at 110th Ann. AIME Meeting, 
Chicago, 111., Feb. 22-26, 1981; 15 pp. To be published by Society 
of Mining Engineers of AIME. 

9. Chase, C. K. , E. A. Nordhousen, R. B. Bhappu, J. B. Fletcher, 

J. V. Rouse, and W. D. Gould. Feasibility of In Situ Leaching of 
Depleted Underground Copper and Uranium Mines. Final Report on BuMines 
Contract J0295045, Mountain States Research and Development, Tucson, 
Ariz., 1981; available for consultation at the Twin Cities Research 
Center, Bureau of Mines, Minneapolis Minn. 



102 



10. D 1 Andrea, D. V., P. G. Chamberlain, and J. K. Ahlness. A Test Blast for 

In Situ Copper Leaching. Pres. at AIME Ann. Meeting, Denver, Colo., 
Feb. 28-Mar. 2, 1978, preprint 78-AS-112, 6 pp. 

11. D 1 Andrea, D. V., P. G. Chamberlain, and L. R. Fletcher. Ground 

Characterization for In Situ Copper Leaching. Trans. AIME Ann. 
Meeting, Las Vegas, Nev. , Feb. 24-28, 1980, 10 pp. 

12. D'Andrea, D. V., R. A. Dick, R. C. Steckley, and W. C. Larson. A 

Fragmentation Experiment for In Situ Extraction. Proc. Solution Mining 
Symp., 103d Ann. meeting, AIME, Dallas, Tex., Feb. 25-27, 1974 (ed. by 
F. F. Apian, W. A. McKinney, and A. D. Pernichele), pp. 148-161. 

13. D'Andrea, D. V., W. C. Larson, P. G. Chamberlain, and J. J. Olson. Some 

Considerations in the Design of Blasts for In Situ Copper Leaching. 

Proc, 17th U. S. Symp. on Rock Mechanics, Snowbird, Utah, Aug. 25-27, 

1976 (pub. as Site Characterization, compiled by W. S. Brown, 

S. J. Green, and W. A. Hustrulid, by the Utah Engineering Experiment 

Station, University of Utah, Salt Lake City, Utah, 1976), 

pp. 5B1-1-5B1-4. Also published in Monograph 1 on Rock Mechanics 

Applications in Mining (ed. by W. S. Brown, S. J. Green, and 

W. A. Hustrulid), SME of AIME, New York, 1977, ch. 24, pp. 201-204. 

14. D'Andrea, D. V., W. C. Larson, L. R. Fletcher, P. G. Chamberlain, and 

W. H. Engelmann. In Situ Leaching Research in a Copper Deposit at the 
Emerald Isle Mine. BuMines RI 8236, 1977, 43 pp. 

15. D'Andrea, D. V., and S. M. Runke. In Situ Copper Leaching Research at 

the Emerald Isle Mine. Proc, Joint MMIJ-AIME Meeting, Denver, Col., 
Sept. 1-3, 1976 (pub. by AIME as World Mining and Metals Technology, 
ed. by A. Weiss), v. 1, pp. 409-419. 

16. Dareing, D. W. , E. T. Wood, and D. H. Davidson. Evaluation of Branch and 

Horizontal Boreholes for In Situ Leach Mining. Final Report, BuMines 
Contract J0199113, Maurer Engineering, Inc., Houston, Tex., 1980, 
149 pp. ; available for consultation at the Twin Cities Research Center, 
Bureau of Mines, Minneapolis, Minn. 

17. Dareing, D. W. , E. T. Wood, D. H. Davidson, and W. C. Larson. Drilling 

and Completing Multiple Branched Boreholes for In Situ Leach Mining. 
Pres. at the Energy-Sources Technology Conf. and Exhibition, 
Houston, Tex., Jan. 18-22, 1981, ASME Preprint 81-Pet-2, 8 pp. 

18. Dick, R. A. In Situ Fragmentation for Solution Mining — A Research Need. 

Pres. at 2d Internat. Symp. on Drilling and Blasting, Phoenix, Ariz., 
Jan. 22-26, 1973, 24 pp. Available from Twin Cities Research Center, 
Bureau of Mines, Minneapolis, Minn. 

19. Engelmann, W. H. Foam Injection Leaching Process for Fragmented Ore. 

U.S. Pat. 4,080, 419, Mar. 21, 1978. 






103 



20. Engelmann, W. H. , and D. R. Kasper. Environmental Regulations for In 

Situ Uranium Mining: From Exploration to Restoration. Pres. at Am. 
Assoc. Petrol. Geol. Ann. Meeting, Houston, Tex., Apr. 1-4, 1979, 
21 pp.; available for consultation at Twin Cities Research Center, 
Bureau of Mines, Minneapolis, Minn. 

21. Engelmann, W.H. , P. E. Phillips, D. R. Tweeton, K. W. Loest, and 

M. T. Nigbor. Restoration of Groundwater Quality Following Pilot- 
Scale Acidic In Situ Uranium Leaching at Nine-Mile Lake Site Near 
Casper, Wyoming. Pres. at 55th Ann. Fall Tech. Conf. Soc. Petrol. 
Eng., Dallas, Tex., Sept. 21-24, 1980. Preprint 9494, 24 pp. 

22. Hustrulid, W. A. Blasthole Underreamers for Surface and In Situ Mining 

(Terra Tek, Inc., Salt Lake City, Utah, Final Tech. Rept. on BuMines 
Contract J-265042). BuMines Open File Rept. 148-77, June 1977, 
215 pp.; available from National Technical Information Service, 
Springfield, Va. , PB 273 652/AS. 

23. Kasper, D. R. , and W. H. Engelmann. Compliance With Environmental 

Regulations for In Situ Uranium Mining: From Discovery to Closure. 
Pres. at BuMines Technology Transfer Seminar on In Situ Leaching and 
Borehole Mining of Uranium, Denver, Colo., July 26, 1978, 36 pp.; 
available for consultation at Twin Cities Research Center, Bureau of 
Mines, Minneapolis, Minn. 

24. Kasper, D. R. , H. W. Martin, L. D. Munsey, R. B. Bhappu, and C. K. Chase, 

Environmental Assessment of In Situ Mining (Final Report, 
Contract J0265002 with PRC Toups and Mountain States Research and 
Development. BuMines Open File Rept. 101-80, December 1979, 292 pp.; 
available from National Technical Information Service, Springfield, 
Va., PB 81-106783. 

25. Kehrman, R. F. Detection of Lixiviant Excursions With Geophysical 

Resistance Measurements During In Situ Uranium Leaching (Final Report, 
Contract J0188080 with Westinghouse Electric Corp.), Bumines Open File 
Rept. 5-81, December 1979, 156 pp.; available from National Technical 
Information Service, Springfield, Va. , PB 81-171324. 

26. Kehrman, R. F., A. J. Farstad, and D. R. Tweeton. Use of Resistivity 

Measurements to Monitor Lixiviant Migration During In-Situ Uranium 
Leaching. Pres. at Fall Meeting, Soc. Min. Eng., AIME, Minneapolis, 
Minn., Oct. 22-24, 1980, SME Preprint 80-338, 10 pp. 

27. Kurth, D.I., and R. D. Schmidt. Computer Modeling of Five-Spot Well 

Pattern Fluid Flow During In Situ Uranium Mining. BuMines RI 8287, 
1978, 76 pp. 

28. . Solution Flow Prediction via Computer Models. Trans Am. Nuclear 

Soc, v. 30, November 1978, pp. 101-102. 



104 



29. Larson, D. R. A Report Comparing Open Pit Mining and Heap Leaching With 

an In Situ Leaching System for a Hypothetical Oxide Copper Deposit 
Based on the Characteristics of the Cactus Deposit, Miami, Arizona. 
M.S. Thesis, Univ. Minnesota, Dept. of Mineral and Metallurgical Eng. , 
June 1973, 254 pp. 

30. Larson, W. C. Nomograph for In Situ Uranium Leaching. Eng. and Min. J., 

v. 178, No. 9, 1977, p. 159. 

31. . Uranium In Situ Leach Mining — Environmental Controls. 1st 

Internat. Conf. on Uranium Mine Waste Disposal, Vancouver, British 
Columbia, May 19-21, 1980, pp. 175-192; available through SME of AIME, 
Littleton, Colo. 

32. . Uranium In Situ Leach Mining — A Third Alternative. Pres. at the 

Ann. AAPG Meeting, Houston, Tex., Apr. 1-6, 1979, 23 pp. 

33. . Uranium In Situ Leach Mining in the United States. BuMines 

IC 8777, 1978, 87 pp. 

34. Larson, W. C, and D. V. D'Andrea. In Situ Leaching Bibliography. 

Available from authors at Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn.; continuous updating. 

35. Larson, W. C, and R. J. Morrell. In Situ Leach Mining Method Using 

Branched Single Well for Input and Ouput. U.S. Pat. 4,222,611, 
Sept. 16, 1980, 3 pp. 

36. Mills, W. R. , H. W. Martin, R. B. Bhappu, and W. H. Engelmann. Water 

Quality Aspects Associated With In Situ Uranium Leaching. Pres. at 
ASCE Nat. Speciality Conf. — Energy, Environment and Wild Rivers in 
Water Resources Planning and Management, Moscow, Idaho, 36 pp.; 
available for consultation at the Twin Cities Research Center, Bureau 
of Mines, Minneapolis, Minn. 

37. Morrell, R. J., W. C. Larson, and R. D. Schmidt. Horizontal Injection 

and Recovery Wells for In Situ Leach Mining. U.S. Pat. 4,249,777', 
Feb. 10, 1981, 3 pp. 

38. Olson, J. J. Bureau of Mines Research in In Situ Leaching and Borehole 

(or Slurry) Mining. Pres. for J. J. Olson by D. V. D'Andrea at the 
1977 SME Fall Meeting and Exhibit, St. Louis, Mo., Oct. 19-21, 1977, 
SME Preprint 77-AS-340, 58 pp. 

39. Olson, J. J., W. C. Larson, and D. R. Tweeton. Mining Research for 

Improved In Situ Extraction of Uranium. Pres. at Uranium In Situ 
Leaching Conf., sponsored by AAPG, AIME, SPE, Vail, Colo., Aug. 25-27, 
1976, 37 pp.; available for consultation at Twin Cities Research 
Center, Bureau of Mines, Minneapolis, Minn. 



105 



40. Olson, J. J. , G. A. Savanick, and D. R. Tweeton. In Situ Mining Tech- 

nology for Uranium — A Progress Report on Bureau of Mines Research. 
Proc. 1978 Energy Technology Conf. and Exhibition, Houston, Tex., 
Nov. 6-9, 1978 (pub. as Mining Technology for Energy Resources — 
Advances for the 80 's by The American Society of Mechanical Engi- 
neers, New York, 1979), pp. 35-46. 

41. O'Rourke, J. E., J. E. Randall, and B. K. Ranson. Field Permeability 

Test Methods With Applications to Solution Mining (Final Report on 
Contract J0265054 with Woodward-Clyde Consultants). BuMines Open File 
Rept. 136-77, August 1977, 180 pp.; available from Nation Technical 
Information Service, Springfield, Va., PB 272 452/AS. 

42. Potter, G. M. E. A. Nordhausen, J. B. Fletcher, J. L. Kake, J. V. Rouse, 

and F. Wojtasiak. Feasibility of In Situ Leaching Metallic Ores Other 
Than Copper and Uranium. Final Report on BuMines Contract J0295032, 
Mountain States Research & Development, Tucson, Ariz., 1981; available 
for consultation at the Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn. 

43. Rehm, W. A., D. W. Dareing, and E. T. Wood. Triple Branch Completion 

With Separate Drilling and Completion Templates. BuMines Rept. of 
Inv. MIN-3044, May 1, 1980. 

44. Riding, J. R. , and F. J. Rosswog. Restoration of Groundwater Quality 

After In Situ Uranium Leaching. Final Report, Contract J0275028 with 
Ford, Bacon, and Davis Utah, Inc., August 1979, 360 pp.; available for 
consultation at Twin Cities Research Center, Bureau of Mines, 
Minneapolis, Minn. 

45. Riding, J. R. , F. J. Rosswog, T. D. Chatwin, G. Buma, and D. R. Tweeton. 

Groundwater Restoration for In Situ Solution Mining of Uranium. Pres. 
at the AIME Ann. Meeting, New Orleans, La., Feb. 18-22, 1979, SME 
preprint 79-127, 42 pp. 

46. Savanick, B. A. Water Jet Perforator for Uranium Leaching Wells. Proc. 

1st Conf. on Uranium Mining Technology, Univ. of Nevada, Reno, Nev. , 
Apr. 24-29, 1977 (pub. as Uranium Mining Technology, ed. by Y. S. Kim, 
by Conferences and Institutes, University of Nevada, Reno, Nev., 1977), 
36 pp. 

47. Savanick, G. A., and W. G. Krawza. Well Perforating Method for Solution 

Well Mining. U.S. Pat. 4,113,314, Sept. 12, 1978, 6 pp. 

48. Schmidt, R. D. Computer Modeling of Fluid Flow During Production and 

Environmental Restoration Phases of In Situ Uranium Leaching. BuMines 
RI 8479, 1980, 70 pp. 

49. Selim, A. A. A Decision Analysis Approach to In Situ Extraction of 

Copper. Ph.D Thesis, Univ. Minnesota, Minneapolis, Minn. March 1976, 
659 pp. 



106 



50. Selim, A. A. , and D. H. Yardley. The Design and Cost of a Fragmentation 

System for In Situ Extraction of Copper. Proc. , 14th Symp. on 
Application of Computer Methods in the Mineral Industry (ed. by 
R. V. Ramari), University Park, Pa., Oct. 14-16, 1976. Society of 
Mining Engineers of AIME, New York, 1977, pp. 792-107. 

51. . In Situ Leaching of Copper — An Economic Simulation Approach. 

Pres. at AIME Ann. Meeting, Atlanta, Ga. , Mar. 15, 1977, Preprint 
77-AS-68, 25 pp.; Min. Eng. , v. 30, No. 1, January 1978, pp. 36-39. 

52. Steckley, R. C, W. C. Larson, and D. V. D'Andrea. Blasting Tests in a 

Porphyry Copper Deposit in Preparation for In Situ Extraction. BuMines 
RI 8070, 1975, 47 pp. 

53. Thill, R. E., and E. V. D'Andrea. Acoustic Core Logging in Blast-Damaged 

Rock. Eng. Geo., v. 10, 1976, pp. 13-36. 

54. Toth, G. W. , and J. R. Annett. Cost and Sensitivities Analysis for 

Uranium In Situ Leach Mining. Final Report, BuMines Contract J0199112, 
NUS Corp., Washington, D.C., 1980, 342 pp., available for consultation 
at the Twin Cities Research Center, Bureau of Mines, Minneapolis, Minn. 

55. Tweeton, D. R. Impedance Measuring Method of and Apparatus for Detecting 

Escaping Leach Solution. U.S. Pat. 4,253,063, Feb. 24, 1981, 5 pp. 

56. Tweeton, D. R. , G. R. Anderson, J. K. Ahlness, 0. M. Peterson, and 

W. H. Engelmann. Geochemical Changes During In Situ Uranium Leaching 
With Acid. Proc. New Orleans Symp. Soc. Min. Eng., AIME, New Orleans, 
La., Feb. 18-22, 1979 (Pub. as In Situ Uranium Mining and Ground Water 
Restoration, ed. by W. J. Schlitt and D. A. Shock), pp. 23-51. 

57. Tweeton, D. R. , G. R. Anderson, and W. H. Engelmann. Bureau of Mines 

Research in Injection Well Construction and Environmental Aspects of In 
Situ Uranium Leaching. Pres at AIME Ann. Meeting, Denver, Colo. , 
Feb. 26-Mar. 2, 1978, Preprint 78-AS-lll, 8 pp. 

58. Tweeton, D. R. , and K. Connor. Well Construction Information for In Situ 

Uranium Leaching. BuMines IC 8769, 1978, 19 pp. 

59. Tweeton, D. R. , T. R. Guilinger, W. M. Breland, and R. S. Schechter. The 

Advantages of Conditioning an Orebody With a Chloride Solution Before 
In Situ Uranium Leaching With a Carbonate Solution. Pres. at 
55th Annual Fall Meeting, Soc. Petrol. Eng., AIME, Dallas, Tex., 
Sept. 21-24, 1980, SPE Preprint 9490, 4 pp. 

60. Tweeton, D. R. , and K. A. Peterson. Selection of Lixiviants for In Situ 

Uranium Leaching. BuMines IC 8851, 1981. 

61. U.S. Bureau of Mines. Water Jet Perforation of Well Casings. Technology 

News, No. 48, April 1978. 



107 



62. Wood, E. T. , D. W. Dareing, W. C. Larson, and R. Snyder. Dual Branch 

Containing One Producer and One Injector Well. BuMines Rept. of Inv. , 
May 1, 1980, MIN-3042. 

63. . Triple Branch Completion With Common Drilling and Casing 

Template. BuMines Rept. of Inv., May 1, 1980, MIN-3045. 

64. Wood, E. T. , R. Snyder, W. C. Larson, and D. W. Dareing. Method for 

Completing Horizontal Drain Holes. BuMines Rept. of Inv., May 1, 1980, 
MIN-3043. 



irll.S. GOVERNMENT PRINTING OFFICE: 1981-703-002/55 int.-bu.of min es,p gh.,p a. 25514 



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